20210129Thackston Exhibit 7 Schedule 1-9.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]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-21-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 7
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) JASON R. THACKSTON

FOR AVISTA CORPORATION

(ELECTRIC)

2020 Electric Integrated
Resource Plan
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 1 of 259

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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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
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
Thomas Dempsey Mgr. Thermal Operations and Maintenance Resource Options Tom Pardee Natural Gas Planning Manager Natural Gas Planning
Darrell Soyars Mgr. Corporate Environmental Compliance Environmental
Xin Shane Sr. Power Supply Analyst Ancillary Services
Scott Kinney Director of Power Supply Power Supply
Tom Lienhard Chief Energy Efficiency Engineer Energy Efficiency Damon Fisher Principle Engineer Distribution Planning Randy Gnaedinger Transmission Contracts Analyst Transmission Availability John Gross Mgr. of System Planning Transmission Planning
Garrett Brown Regulatory Policy Analyst Regulatory
Annie Gannon Communications Manager Communications

Contact contributors via email by placing their names in this email address format:
[e-mail]
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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2020 Electric IRP Introduction
Avista has a 130-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 2020 Integrated Resource Plan (IRP) continues our legacy by looking 25 years into the future to determine the energy needs of our customers. The IRP analyzes and outlines a strategy to meet demand and clean energy requirements using demand and supply side resources. Summary The 2020 IRP shows Avista has adequate resources between owned and contractually controlled generation 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 2017 IRP include:
• The energy forecast grows 0.3 percent per year, replacing the 0.5 percent annual growth rate in the last IRP.
• Peak load growth is 0.3 percent in the winter and 0.4 percent in the summer.
• Energy efficiency meets 71 percent of new load growth compared to 53 percent in the 2017 IRP. Highlights
Some highlights of the 2020 IRP include:
• The resource strategy reduces greenhouse gas emissions between 80-90 percent from
present levels.
• A combination of new wind, storage, and demand response will meet the capacity losses from coal and natural gas-fired generation by 2026.
• A larger portfolio of new resources than in previous IRPs to meet expected resource retirements and new renewable energy goals.
• As much as 300 MW of new renewable generation by 2023 and a further 200 MW by 2027. 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 75 participants to develop each plan. The participants in the public process include customers, academics, environmental 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 2021 IRP in early 2020. 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, 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
Action Items .............................................................................................................................. 1-8 2. Introduction and Stakeholder Involvement ................................................................ 2-1
IRP Process ............................................................................................................................. 2-1 2020 IRP Outline ...................................................................................................................... 2-4
Idaho Regulatory Requirements .............................................................................................. 2-5 Washington Regulatory Requirements .................................................................................. 2-10
Summary of 2020 IRP Changes from the 2017 IRP .............................................................. 2-11 3. Economic & Load Forecast .......................................................................................... 3-1
Economic Characteristics of Avista’s Service Territory ............................................................ 3-1 IRP Long-Run Load Forecast ................................................................................................ 3-13
Monthly Peak Load Forecast Methodology ............................................................................ 3-18 Simulated Extreme Weather Conditions with Historical Weather Data ................................. 3-19 4. Existing Supply Resources .......................................................................................... 4-1 Spokane River Hydroelectric Developments ........................................................................... 4-2
Clark Fork River Hydroelectric Development ........................................................................... 4-4 Total Hydroelectric Generation ................................................................................................ 4-4
Thermal Resources .................................................................................................................. 4-5 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 ................................................................................................................................... 4-17 5. Energy Efficiency .......................................................................................................... 5-1
The Conservation Potential Assessment ................................................................................. 5-2 Energy Efficiency Targets ........................................................................................................ 5-6
Energy Efficiency Related Financial Impacts ......................................................................... 5-10 Integrating Results into Business Planning and Operations .................................................. 5-11
Conservation’s T&D Deferral Analysis ................................................................................... 5-13 6. Demand Response ........................................................................................................ 6-1
Demand Response Program Descriptions ............................................................................... 6-5 Demand Response Program Participation ............................................................................... 6-7
Demand Response Program Results ....................................................................................... 6-8 Demand Response Program Cost Estimates ........................................................................ 6-11
Washington State House Bill 1444 Appliance Standards ...................................................... 6-11 7. Long-Term Position ....................................................................................................... 7-1
Reserve Margins ...................................................................................................................... 7-1 Balancing Loads and Resources ............................................................................................. 7-3
Washington State Renewable Portfolio Standard .................................................................... 7-6 Washington State Clean Energy Transformation Act (CETA) ................................................. 7-7
Avista’s Clean Energy Goal ..................................................................................................... 7-8 Regional Resource Adequacy .................................................................................................. 7-9 8. Transmission & Distribution Planning ........................................................................ 8-1 Avista Transmission System .................................................................................................... 8-1
Transmission Planning Requirements and Processes ............................................................ 8-2 System Planning Assessment .................................................................................................. 8-4
IRP Generation Interconnection Options ................................................................................. 8-5
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Distribution Planning ................................................................................................................ 8-8 Merchant Transmission Rights ............................................................................................... 8-11 9. Supply-Side Resource Options .................................................................................... 9-1 Assumptions ............................................................................................................................. 9-1 Natural Gas-Fired Combined Cycle Combustion Turbine ........................................................ 9-3 Hydroelectric Project Upgrades and Options ......................................................................... 9-21 Thermal Resource Upgrade Options ..................................................................................... 9-24 Intermittent Generation Costs ................................................................................................ 9-24 Ancillary Services Values ....................................................................................................... 9-25 Resource ELCC Analysis ....................................................................................................... 9-26 Other Environmental Considerations ..................................................................................... 9-27 Market Analysis ........................................................................................................... 10-1 Electric Marketplace ............................................................................................................... 10-2 Western Interconnect Loads .................................................................................................. 10-3 Generation Resources ........................................................................................................... 10-5 Generation Operating Characteristics .................................................................................... 10-7 Electric Resource and Emissions Forecast ......................................................................... 10-15 Electric Market Price Forecast ............................................................................................. 10-19 Scenario Analysis ................................................................................................................. 10-24 11. Preferred Resource Strategy ...................................................................................... 11-1 Resource Selection Process .................................................................................................. 11-2 The Preferred Resource Strategy .......................................................................................... 11-3 Avoided Cost ........................................................................................................................ 11-20 12. Portfolio Scenario Analysis ........................................................................................ 12-1 Portfolio Scenarios ................................................................................................................. 12-3 Cost and Rate Comparison .................................................................................................. 12-19 Greenhouse Gas Analysis ................................................................................................... 12-21 Risk Analysis ........................................................................................................................ 12-24 Market Price Sensitivities ..................................................................................................... 12-28 Electrification Scenario ......................................................................................................... 12-31 13. Action Items ................................................................................................................. 13-1 Summary of the 2017 IRP Action Plan................................................................................... 13-1 2020 IRP Two Year Action Plan ............................................................................................. 13-4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, 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: Annual and Cumulative Energy Efficiency Acquisitions ............................................. 1-4
Figure 1.5: Portfolio Scenario Analysis......................................................................................... 1-6 Figure 1.6: Avista’s Qualifying Renewables for Washington State’s EIA ..................................... 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, 2018 .............................. 3-3
Figure 3.4: Avista and U.S. MSA Non-Farm Employment Growth, 2010-2019 ........................... 3-4 Figure 3.5: MSA Personal Income Breakdown by Major Source, 2018 ....................................... 3-5
Figure 3.6: Avista and U.S. MSA Real Personal Income Growth, 1970-2018 ............................. 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 ................................................... 3-15
Figure 3.12: Average Megawatts, High/Low Economic Growth Scenarios ................................ 3-16 Figure 3.13: UPC Growth Forecast Comparison to EIA ............................................................. 3-17
Figure 3.14: Load Growth Comparison to EIA ........................................................................... 3-17 Figure 3.15: Peak Load Forecast 2020-2045 ............................................................................. 3-21
Figure 3.16: Peak Load Forecast with 1 in 20 High/Low Bounds, 2020-2045 ........................... 3-22 Figure 4.1: 2020 Avista Capability and Energy Fuel Mix ............................................................. 4-1
Figure 4.2: 2018 Fuel Mix Disclosure ........................................................................................... 4-2 Figure 4.3: Avista’s Net Metering Customers ............................................................................. 4-11
Figure 4.4: Avista’s 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 MWh .............................. 5-7
Figure 5.4: Idaho Energy Efficiency Savings by Segment ........................................................... 5-7 Figure 5.5: Washington Energy Efficiency Savings by Segment ................................................. 5-8
Figure 5.6: Washington Annual Achievable Potential Energy Efficiency (Megawatt Hours)........ 5-9 Figure 5.7: Cumulative Energy Efficiency Costs ........................................................................ 5-10
Figure 6.1: Program Characterization Process ............................................................................ 6-3 Figure 7.1: Winter One-Hour Capacity Load and Resources ....................................................... 7-4
Figure 7.2: Summer One-Hour Capacity Load and Resources ................................................... 7-4 Figure 7.3: Annual Average Energy Load and Resources ........................................................... 7-5
Figure 7.4: Washington State CETA Compliance ........................................................................ 7-8 Figure 7.5: Avista Clean Energy Goal .......................................................................................... 7-9
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 Figure 9.1: Lithium-ion Capital Cost Forecast ............................................................................ 9-12
Figure 9.2: Wholesale Hydrogen Costs per Kilogram ................................................................ 9-16 Figure 9.3: Historical and Planned Hydro Upgrades .................................................................. 9-22
Figure 10.1: NERC Interconnection Map ................................................................................... 10-3 Figure 10.2: 25-Year Annual Average Western Interconnect Load Forecast ............................ 10-4
Figure 10.3: Cumulative Resource Retirement Forecast ........................................................... 10-6 Figure 10.4: Western Generation Resource Additions (Nameplate Capacity) ........................... 10-7
Figure 10.5: Henry Hub Natural Gas Price Forecast .................................................................. 10-8 Figure 10.6: Stochastic Stanfield Natural Gas Price Forecast ................................................. 10-10
Figure 10.7: Stanfield Nominal 20-Year Nominal Levelized Price Distribution ........................ 10-10
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Figure 10.8: Northwest Expected Energy ................................................................................. 10-12 Figure 10.9: Generation Technology History and Forecast ..................................................... 10-15 Figure 10.10: Northwest Generation Technology History and Forecast .................................. 10-16 Figure 10.11: Wind and Solar Curtailment Forecast ................................................................ 10-17 Figure 10.12: 2017 Greenhouse Gas Emissions ..................................................................... 10-18 Figure 10.13: Greenhouse Gas Emissions Forecast ............................................................... 10-18 Figure 10.14: Northwest Regional Greenhouse Gas Emissions Intensity ............................... 10-19 Figure 10.14: Mid-Columbia Electric Price Forecast Range .................................................... 10-20 Figure 10.15: Winter Average Hourly Electric Prices (December - February) ......................... 10-22 Figure 10.16: Spring Average Hourly Electric Prices (March - June) ....................................... 10-23 Figure 10.17: Summer Average Hourly Electric Prices (July - September) ............................. 10-23 Figure 10.18: Autumn Average Hourly Electric Prices (October - November) ......................... 10-24 Figure 10.19: Mid-Columbia Nominal Levelized Prices Scenario Analysis .............................. 10-26 Figure 10.20: Mid-Columbia Annual Electric Price Scenario Analysis ..................................... 10-26 Figure 10.21: 2040 Western Interconnect Generation Forecast .............................................. 10-27 Figure 10.22: 2021-2045 Levelized Greenhouse Gas Emissions ............................................ 10-28 Figure 11.1: Demand Response................................................................................................. 11-9 Figure 11.2: Energy Efficiency Savings Programs ................................................................... 11-11 Figure 11.3: Percent Change in Revenue Requirement .......................................................... 11-13 Figure 11.4: Utility Revenue Requirement ............................................................................... 11-14 Figure 11.5: Annual Clean Energy ........................................................................................... 11-15 Figure 11.6: Greenhouse Gas Emissions ................................................................................ 11-17 Figure 11.7: Total Net Greenhouse Gas Emissions Intensity .................................................. 11-17 Figure 11.8: Energy Efficiency GHG Emissions Savings ......................................................... 11-18 Figure 11.9: Clean Energy Mix Forecast .................................................................................. 11-19 Figure 11.10: Avoided Cost of Energy Efficiency ..................................................................... 11-24 Figure 12.1: Resource Acquisition Roadmap ............................................................................. 12-2 Figure 12.2: Idaho Clean Energy Plan Rate Impacts ................................................................. 12-6 Figure 12.3: Portfolio Average Energy Rates ........................................................................... 12-20 Figure 12.4: Portfolio Average Energy Levelized Revenue Requirement ................................ 12-21 Figure 12.5: Portfolio Annual Greenhouse Gas Emissions ...................................................... 12-22 Figure 12.6: Levelized Greenhouse Gas Emissions ................................................................ 12-23 Figure 12.7: Change in Greenhouse Gas Emissions Compared to Change in Cost ............... 12-23 Figure 12.8: Conceptual Efficient Frontier Curve ..................................................................... 12-24 Figure 12.9: Portfolios Compared to the Efficient Frontier ....................................................... 12-25 Figure 12.10: Portfolio TailVar95 Analysis ............................................................................... 12-26 Figure 12.11: Portfolio PVRR with Risk Analysis ..................................................................... 12-27 Figure 12.12: Electrification Scenario: EV Forecast Comparison ............................................ 12-32 Figure 12.13: Electrification Scenario: EV Load Forecast Comparison ................................... 12-32 Figure 12.14: Electrification Scenario: Rooftop Solar Customer Count Comparison ............... 12-34 Figure 12.15: Electrification Scenario: Rooftop Solar Load Changes ...................................... 12-34 Figure 12.16: Electrification Scenario: Electric Customer’s with Natural Gas .......................... 12-35 Figure 12.17: 2017 Avista’s Core Natural Gas Load ................................................................ 12-36 Figure 12.18: Natural Gas to Electric Efficiency Rates Based on Daily NG use ...................... 12-37 Figure 12.19: Electrification Scenario: Load with Natural Gas Customer Conversions ........... 12-38 Figure 12.20: Electrification Scenario: Total Load Changes .................................................... 12-39

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table of Tables

Table 1.1: The 2020 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 3.1: UPC Models Using Non-Weather Driver Variables ..................................................... 3-9
Table 3.2: Customer Growth Correlations, January 1998 – December 2018 ............................ 3-11 Table 3.3: High/Low Economic Growth Scenarios (2020-2045) ................................................ 3-15
Table 3.4: Load Growth for High/Low Economic Growth Scenarios (2020-2045) ..................... 3-16 Table 3.5: Forecasted Winter and Summer Peak Growth, 2020-2045 ...................................... 3-21
Table 3.6: Energy and Peak Forecasts ...................................................................................... 3-23 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 ............................................................ 4-15
Table 4.11: Colstrip Costs Modelled in the IRP (millions) .......................................................... 4-20 Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ...................... 5-5
Table 5.2: Biennial Conservation Target for Washington Energy Efficiency ................................ 5-9 Table 5.3: Annual Achievable Potential Energy Efficiency (Megawatt Hours) ............................. 5-9
Table 5.4: Transmission and Distribution Benefit ....................................................................... 5-14 Table 6.1: Demand Response Program Options by Market Segment ......................................... 6-4
Table 6.2: Demand Response Achievable Potential (MW) – Winter DLC ................................... 6-8 Table 6.3: Demand Response Achievable Potential (MW) – Summer DLC ................................ 6-9
Table 6.4: Winter Demand Response Achievable Potential (MW) ............................................... 6-9 Table 6.5: Summer Demand Response Achievable Potential (MW) ......................................... 6-10
Table 6.6: 2021 Levelized Costs by DR Program (Standalone) ............................................. 6-11 Table 7.1: 2020 Reliability Study Results ..................................................................................... 7-3
Table 7.2: Washington State EIA Compliance Position Prior to REC Banking (aMW) ................ 7-6 Table 7.3: NPCC 2024 Resource Adequacy Analysis ............................................................... 7-10
Table 8.1: 2020 IRP Generation Study Transmission Costs ........................................................ 8-6 Table 8.2: Third-Party Large Generation Interconnection Requests ............................................ 8-7
Table 8.3: Planned Feeder Rebuilds .......................................................................................... 8-10 Table 8.4: Merchant Transmission Rights .................................................................................. 8-11
Table 9.1: 2020 Natural Gas-Fired Plant Levelized Costs ........................................................... 9-5 Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics................................... 9-5
Table 9.3: Levelized Wind Prices ($/MWh) .................................................................................. 9-7 Table 9.4: Levelized Solar Prices ................................................................................................. 9-8
Table 9.5: Storage Cost w/ Solar System ($/kW-month).............................................................. 9-9 Table 9.6: Lithium-ion Levelized Cost $/kWh ............................................................................. 9-13
Table 9.7: Flow Battery Levelized Cost $/kWh ........................................................................... 9-14 Table 9.8: Hydrogen Storage and Fuel Cell Levelized Cost $/kWh ........................................... 9-17
Table 9.9: Hydroelectric Upgrade Options ................................................................................. 9-23 Table 9.10: Ancillary Services Value Estimates (2020 dollars) .................................................. 9-26
Table 9.11: Peak Credit .............................................................................................................. 9-27 Table 9.12: Natural Gas Fugitive Emissions .............................................................................. 9-28
Table 10.1: AURORAXMP Zones ................................................................................................. 10-3 Table 10.2: Natural Gas Price Basin Differentials from Henry Hub ........................................... 10-9
Table 10.3: Nominal Levelized Flat Mid-Columbia Electric Price Forecast.............................. 10-20 Table 10.4: Annual Average Mid-Columbia Electric Prices ($/MWh) ....................................... 10-21
Table 10.5: Change in 2040 Regional Generation (Percent) ................................................... 10-27
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Table 11.2: 2020 Preferred Resource Strategy (2031-2040) ..................................................... 11-7 Table 11.3: 2020 Preferred Resource Strategy (2041-2045) ..................................................... 11-8 Table 11.4: PRS Demand Response Programs ......................................................................... 11-9 Table 11.5: Energy Efficiency Selected by PRiSM vs. Added to the Load Forecast ............... 11-10 Table 11.6: 2030 Reliability Metrics.......................................................................................... 11-12 Table 11.6: New Resource Avoided Costs ............................................................................... 11-22 Table 11.7: New Resource Avoided Costs With Renewable Tax Credits ................................ 11-23 Table 12.1: Portfolio #1- Preferred Resource Strategy .............................................................. 12-3 Table 12.2: Portfolio #2- Least Cost Plan- without CETA .......................................................... 12-4 Table 12.3: Portfolio #3- Clean Energy Plan .............................................................................. 12-5 Table 12.4: Portfolio #4- Clean Energy Plan .............................................................................. 12-6 Table 12.5: Portfolio #5- CEP and No CTs by 2045................................................................... 12-7 Table 12.6: Portfolio #6- LC without Pumped Hydro or Long Lake Upgrade ............................. 12-8 Table 12.7: Least Cost Plan with Colstrip extended to 2035, without CETA ............................. 12-9 Table 12.8: Least Cost Plan with Colstrip extended to 2035, with CETA ................................ 12-10 Table 12.9: Least Cost Plan with 30 Percent Higher Pumped Hydro Storage Costs .............. 12-11 Table 12.10: Least Cost Plan with Federal Tax Credits Extension .......................................... 12-12 Table 12.11: Least Cost Plan with Federal Tax Credits Extension .......................................... 12-13 Table 12.12: Low Economic Growth......................................................................................... 12-14 Table 12.13: High Economic Growth ........................................................................................ 12-15 Table 12.14: Least Cost Plan with Lancaster Extended Five Years ........................................ 12-16 Table 12.15: Least Cost Plan with Colstrip 4 Extended to 2035 .............................................. 12-17 Table 12.16: Resource Selection Matrix .................................................................................. 12-18 Table 12.17: Portfolio Costs and Rates .................................................................................... 12-19 Table 12.18: Change in Cost (PVRR) Compared to Expected Case ....................................... 12-29 Table 12.19: Change in Cost (PVRR) Compared to PRS ........................................................ 12-29 Table 12.20: Levelized Greenhouse Gas Emissions vs. Expected Case ................................ 12-30 Table 12.21: Change in Levelized Greenhouse Gas Emissions Compared to the PRS ......... 12-30 Table 12.22: Electrification Scenario: Emission Changes in Millions of Metric Tons ............... 12-40

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Appendix Table of Contents

Appendix A – 2020 IRP Technical Advisory Committee Presentations
Appendix B – 2020 Electric IRP Work Plan Appendix C – Confidential Historical Generation Operating Data
Appendix D – AEG Conservation Potential Assessment
Appendix E – Conservation Potential Assessment Measure Assumptions Appendix F – Resource Adequacy in the Pacific Northwest by E3
Appendix G – New Resource Table for Transmission Appendix H – New Resource Cost Assumptions
Appendix I – Black and Veatch Renewable Resource and Storage Study Appendix J – Confidential Report of Portfolio #14

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1. Executive Summary

The 2020 Electric Integrated Resource Plan (IRP) shapes Avista’s resource strategy and planned procurements for the next 25 years. It provides a snapshot of existing resources and Avista’s load forecast. The plan evaluates supply and demand-side resource options in multiple resource selection strategies over expected and possible future conditions to
determine an optimal strategy to serve customers. The Preferred Resource Strategy (PRS) relies on modeling methods to balance cost, reliability, rate volatility, and environmental goals and mandates. Avista’s management and Technical Advisory Committee (TAC) guide IRP development through their 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
Under extreme cold, Avista expects its highest peak load in the winter. Avista’s peak planning methodology considers operating reserves, regulation, load following, wind integration, and resource adequacy requirements. The Company has adequate
resources and conservation programs to meet peak load requirements through December
2025. Figure 1.1 shows Avista’s resource position through 2045. Chapter 7 – Long-Term Position details Avista’s projected resource needs. Load growth and the loss of Colstrip1, Lancaster, Northeast and the loss of 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 customers after 2025, although the owners have not made a decision on the future of the plant.
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Modeling and Results
Avista uses a multistep process to develop its PRS, beginning with identifying and quantifying potential new resources to serve projected electricity demand across the Western Interconnect. This study determines the impact of external markets on the
Northwest electricity marketplace. It then maps existing Avista resources to the
transmission grid in a model simulating hourly operations for the Western Interconnect in the 2021 to 2045 IRP timeframe. The model adds new resources and transmission throughout the region as loads grow and resources retire. Monte Carlo-style analyses vary hydroelectric and wind generation, loads, 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. Figure 1.2 shows the 2020 IRP Mid-Columbia electricity price forecast for the Expected Case, including the range of prices from 500 Monte Carlo iterations. The levelized price
is $27.86 per MWh in nominal dollars over the 2021-2045 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 is $3.51 per dekatherm (Dth) over the next 25 years. See Chapter 10 – Market Analysis for natural gas and electricity price forecasts.

Average 10th percentile Median 95th percentile Deterministic
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 potential applications in its service area. These
studies evaluate over 6,000 potential energy efficiency programs and 17 Demand Response programs. Avista’s commitment to energy efficiency is evident by loads that are 12.2 percent lower 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 our system today.2 Energy efficiency will serve 71 percent
of future load growth. This is an increase from 53 percent in the prior IRP. See Chapter 5 – Energy Efficiency for more information. Going forward Demand Response programs will be an integral part of 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.
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Figure 1.4: Annual and Cumulative Energy Efficiency Acquisitions
Preferred Resource Strategy
The PRS results from careful consideration and input by Avista’s management, the TAC, and from the information gathered and analyzed in the IRP process. It meets future requirements with upgrades at existing generation facilities (thermal and hydroelectric), energy efficiency, energy storage, contracts, new renewable resources, and demand response, as shown in Table 1.1.

The 2020 PRS is a reasonable low-cost plan to meet both reliability and environmental requirements. Major changes from the 2017 IRP include the removal of new natural gas-fired peakers in exchange for long duration energy storage, additional demand response, 500 MW of new wind resources, and upgrades to thermal and hydroelectric facilities.

Each new supply-side resource and demand-side 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 their 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
developing optimal mixes of new resources. The resource plan may change depending on the final rulemaking and requirements of complying with the Clean Energy Transformation Act in Washington State and whether projects identified in the IRP are cost competitive and available at the time of need.
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Table 1.1: The 2020 Preferred Resource Strategy
Resource Type Year Capability (MW)
The PRS provides a least reasonable-cost portfolio, minimizing future costs and risks within actual and expected environmental constraints. The Efficient Frontier illustrates the
tradeoffs between risk and cost in an approach similar to finding an optimal mix of risk and return in an investment portfolio; 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 Efficient Frontier (black line). Lower power cost variability comes from investments in more
expensive, but less risky, resources such as wind and hydroelectric upgrades. The PRS is the portfolio selected on the Efficient Frontier where reduced risk justifies the increased cost of the portfolio selection. Chapter 12 – Portfolio Scenarios includes several scenarios identifying tipping points
where the PRS could change under different conditions and alternate market futures. It also evaluates the impacts of varying load growth, resource capital costs, and greenhouse gas policies.
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Figure 1.5: Portfolio Scenario Analysis
Clean Energy Goals
Acquiring an additional 500 MW (by 2027) of new wind resources along with upgrades to its hydroelectric and biomass facilities will position Avista to meet or exceed Washington’s clean energy requirements. Energy storage will be key to removing carbon-emitting resources from our portfolio; our plans for combining long duration pumped hydro, liquid
air energy storage (LAES) and lithium-ion technology provide the reliable capacity
required to meet long cold winter periods where weather- and sun-dependent renewable resources do not always contribute to load service. The PRS meets nearly 89 percent of Avista’s own clean energy goal to provide our customers with 100 percent net clean energy by 2027 at competitive prices. Figure 1.6 is the comparison between Avista’s total
energy sales (Idaho and Washington) and the annual average clean energy resources
serving customers. Our plan complies with the goals of Washington’s Energy Independence Act, relying on our Palouse Wind contract, generation from our Kettle Falls biomass facility, and upgrades to our Clark Fork and Spokane River hydroelectric developments.

2. LCP-w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP-No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA 9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits extended
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
15. Colstrip 4-2035
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Figure 1.6: Avista’s Qualifying Renewables for Washington State’s EIA
The shift to clean energy will reduce our greenhouse gas footprint significantly. Figure 1.7 shows Avista’s emissions will decrease from 2018 levels by 79 percent in 2030 and 85 percent by 2045. When accounting for our contributions through incentives and programs to shift transportation fuel from petroleum to electricity, regional greenhouse gas
reductions will be much greater than just from the removal of coal- and natural gas-fired generation shown below.
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Figure 1.7: Avista Greenhouse Gas Emissions Forecast
Action Items
The 2020 Action Items chapter updates progress made on Action Items in the 2017 IRP and outlines activities Avista intends to perform between the publication of this report and publication of the next IRP. Items reflect input from staff at both of our state regulatory
bodies, Avista’s management team, and the TAC. Refer to Chapter 13 – Action Items for
details about each of these categories.
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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 2020 IRP is Avista’s sixteenth plan. It identifies and describes a Preferred Resource Strategy to meet load growth, resource deficits, and environmental mandates 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 and optimizing the value of its current portfolio. The IRP is a resource evaluation tool, not a plan for acquiring a particular set of assets. Actual resource acquisition generally occurs through competitive bidding processes. IRP Process
The IRP process originally began as the 2019 IRP with Avista’s first Technical Advisory Committee (TAC) on July 25, 2018. In March 2019, Avista requested both Washington
and Idaho to delay the IRP filing by six months, effectively creating the 2020 IRP cycle.
The reason for the request was due to pending legislation in many states, including Washington, to change energy laws and regulations. Ultimately, Washington State passed the Clean Energy Transformation Act (CETA) while other states ended their legislative sessions without major changes. The Idaho Commission agreed with this
change on April 16, 2019 in Order 34312 to change the IRP filing date to February 28,
2020. Washington also agreed with the change in filing dates but ultimately deferred this filing a second time in Order 2 of UE-180738 until 2021 because of CETA rulemaking requirements in the law.
The 2020 IRP is developed and written with the aid of a public process. Avista actively
seeks input from a variety of constituents through its 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 engage in the planning
process. Avista distributed a draft of its work plan at the first of six TAC meetings for the 2020 IRP. Each TAC meeting covers different aspects of IRP planning activities. At the meetings, members provide contributions to, and assessments of, modeling assumptions, modeling processes, and results of Avista studies. Table 2.1 contains a list of TAC meeting dates and the agenda items covered in each meeting.
Appendix A and Avista’s website2 include the agendas, presentations, and meeting notes from the 2020 IRP TAC meetings. The website also contains IRPs and TAC meeting
1 Washington IRP requirements are contained 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 https://www.myavista.com/about-us/our-company/integrated-resource-planning
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presentations back to 1989. The final work plan which, incorporates changes in the schedule, is included in Appendix B.
Table 2.1: TAC Meeting Dates and Agenda Items
Meeting Date Agenda Items •
• 2017 IRP Commission Acknowledgements
• Demand and Economic Forecast
• Hydro One Merger Agreements
• 2017 Acton Plan Updates
•
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• Modeling Process Overview
• Generation Resource Options
• Home Heating Technologies Overview
• Resource Adequacy and Effective Load Carrying Capability (ELCC)
• Electric IRP Key Assumptions
•
•
• Regional Legislative Update
• IRP Transmission Planning Studies
• Distribution Planning within the IRP
• Conservation Potential Assessment
• Demand Response Potential Assessment
• Review
• E3 Study-
•
• Washington SB 5116 and IRP Updates
• Energy and Peak Load Forecast Update
• Natural Gas Price Forecast
• Electric Price Forecast
• Existing Resource Overview
• •
• Energy Imbalance Market Update
• Storage and Ancillary Service Analysis
• Preliminary Preferred Resource Strategy
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• Review of Preferred Resource Strategy
• Portfolio Scenario Results
•

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Avista greatly appreciates the valuable contributions of its TAC members and wishes to acknowledge and thank the organizations that allow their attendance. Table 2.2 is a list
of the organizations participating in the 2019/20 IRP TAC process. Table 2.2: External Technical Advisory Committee Participating Organizations
Organization
Future Public Involvement Avista actively solicits input from interested parties to enhance its IRP process. We continue to expand TAC membership and diversity while maintaining the TAC meetings as an open public process.

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2020 IRP Outline
The 2020 IRP consists of 13 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 2020 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 past
demand response 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 flexibility.
Chapter 8: Transmission & Distribution Planning This chapter discusses Avista distribution and transmission systems, as well as regional transmission planning issues. It includes detail on transmission cost studies used in IRP
modeling and summarizes of our 10-year Transmission Plan. The chapter concludes with
a discussion of distribution efficiency and grid modernization projects; including storage benefits to the distribution system. Chapter 9: Generation Resource Options
This chapter covers the costs and operating characteristics of supply side resource
options modeled for the IRP. Chapter 10: Market Analysis This chapter details Avista IRP modeling and its analyses of the wholesale market.

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Chapter 11: Preferred Resource Strategy This chapter details the resource selection process used to develop the 2020 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: Action Items This chapter discusses progress made on Action Items contained in the 2017 IRP. It details the action items Avista will focus on between publication of this plan and the 2021 IRP(s).
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 analysis 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 below3; 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 appendix4: 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;
3 Resources less than three megawatts should be grouped as a single resource in the appropriate category.
4 FERC Form 714 can be on-line at https://www.ferc.gov/docs-filing/forms/form-714/data.asp
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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 insure 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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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. 2017 IRP Discussion and Findings
Text is from IPUC Order 33971, Case No. AVU-E-17-08 In doing so, we reiterate that an IRP is a working document that incorporates many assumptions and projections at a specific point in time. It is a plan, not a blueprint, and
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by issuing this Order we merely acknowledge the Company's ongoing planning process, not the conclusions or results reached through that process. With this Order, the
Commission is not approving the IRP or any resource acquisitions referenced in it, endorsing any particular element in it, or opining on the Company's prudence in selecting the IRP's preferred resource portfolio. The appropriate place to determine the prudence of the IRP or the Company's decision to follow or not follow it, and the validation of predicted performance under the IRP, will be a general rate case or another proceeding
in which the issue’s noticed. The Commission appreciates the active participation in the IRP process of the Staff, ICL, and other stakeholders and customers, and we are confident that their input helps the Company develop a better and more comprehensive IRP. We note that customers and
Staff commented on alternatives regarding the closure of Colstrip and the inclusion in the PRS of a new gas peaker plant after the expiration of the Lancaster agreement. We encourage the Company to continue evaluating all options regarding these resources, and to consider the best interests of its customers when developing the 2019 IRP. The Commission appreciates the Company's collaboration with stakeholders in developing
the 2017 Electric IRP. Washington Regulatory Requirements
Avista typically files its Electric IRP in both Washington and Idaho. The Washington Commission ruled in Order 2 from Docket UE-180738 Avista to be compliant with the IRP rules when it filed a Progress Report on October 25, 2019. This ruling was in partly due to passage of the Clean Energy Transformation Act (CETA) where the Commission needs to complete certain rulemaking prior to acknowledging any plans under their jurisdiction.
CETA requires new rules for IRPs because of new requirements and new reports; including the development of the Clean Energy Action Plan (CEAP) and the Clean Energy Implementation Plan (CEIP). This rule making process must finish prior to December 31, 2020. Some of the new requirements Avista must consider include accounting for the social cost of carbon, removal of coal from Washington retail rates after 2025,
transformation to 100 percent clean energy, distribution and transmission planning within the IRP, accounting for economic, health, and environmental burdens and benefits. Avista’s intention in this IRP is to model a future IRP/CEAP taking into account potential rules as described in CETA to meet resource plan requirements for a least reasonable
cost reliable system. This IRP will not be an official filing in Washington for acknowledgement, but Avista will filed it as an advisory report of Avista’s ongoing resource planning efforts. Avista anticipates this plan will change because of final rulemaking, but this IRP provides the Company and stakeholders a practical plan addressing new requirements and potential techniques to solve those new requirements.

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Summary of 2020 IRP Changes from the 2017 IRP
This summary provides an overview of major changes in the analysis since the 2017 IRP. This section does not describe the specific changes, but rather it briefs readers regarding significant or major methodological changes.
Capacity and Energy Position, Including Load Forecasting
• This IRP uses a 5 percent LOLP for the PRS rather than the 2017 IRP’s 14 percent winter planning margin and 7 percent summer planning margin. This change resulted in an 18 percent planning margin for the PRS.
• Load forecast includes adjustments for natural gas penetration.
• Assumes Colstrip exits the portfolio in 2025, and then studies the cost impacts of extending the project to 2035.
• Assumes the Northeast CT retires in 2035. Energy Efficiency and Demand Response
• Idaho energy efficiency analysis uses the Utility Cost Test (UCT) for programs 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 proscribed in CETA. The savings assumes the average emissions
from the regional power system on an annual basis.
• This IRP uses a full demand response (DR) potential assessment for potential DR programs for both residential and commercial/industrial customers. The previous
DR potential study only focused on commercial and industrial customers with a description of potential residential programs. Supply-Side Resource Options
• Avista modelled several energy storage options in this IRP including pumped hydro storage, lithium-ion, vanadium flow, zinc bromide flow, liquid air, and hydrogen all with varying energy durations. The previous IRP modeled storage generically.
• This IRP models wind, solar, pumped hydro storage, nuclear, and geothermal as
purchase power agreements; whereas the previous IRPs assumed these
resources were in Avista’s rate base (i.e. owned by Avista).
• Avista assigned peak credits to renewable and storage resources depending on their ability to meet peak loads using its ARAM model.
• This IRP includes the cost of upstream greenhouse gas emissions from the natural gas-fired projects at the social cost of carbon for Washington’s share of resources.
• The IRP analysis uses a regional emissions factor for market purchases and sales
to adjust greenhouse emissions reporting for the PRS. 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,
natural gas price forecast from two consultants, and regional hydro conditions.
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• The Aurora capacity expansion study is required to meet the qualifications of state
clean energy policies including CETA. The model must also meet a 5 percent LOLP threshold for reliability when selecting new resources.
• A cap and trade greenhouse gas emissions cap applies in modeling Oregon.
• This IRP used two consultant forecasts along with market forward prices for the natural gas price forecast. The previous IRP used only one consultant forecast along with forward prices. Portfolio Optimization Analysis
• The 2020 IRP optimizes a resource portfolio for 25 years instead of 20 years. Moving to 25 years led to removing some of the cost estimates for resource beyond 20 years.
• Includes social cost of carbon costs for Washington’s share of resource emissions
and market purchases for new resource acquisitions, DR programs, and energy efficiency. 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.
• Models the clean energy requirements of CETA in Washington State.
• Includes total customer rate estimates as compared to previous IRP’s showing only power supply costs.
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3. Economic & Load Forecast

An explanation and quantification of Avista’s loads and resources are integral to the IRP. This chapter summarizes customer and load projections, load growth scenarios, and recent enhancements to 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. 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 that when regional employment growth is stronger than U.S. growth over the business cycle, it is associated with increased in-migration. The reverse holds true. Figure 3.1 shows annual population growth since 1971 and highlights the
recessions. 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 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.

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 2020 energy forecast grows 0.3 percent per year, replacing the 0.5 percent
annual growth rate in the 2017 IRP.
• Peak load growth is 0.3 percent in the winter and 0.4 percent in the summer.
• Retail sales and residential use per customer forecasts continue to decline from
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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.; 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. 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 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.
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.
3 Data Source: Bureau of Economic Analysis, U.S. Census, and Washington State OFM. 4 Data Source: Bureau of Labor and Statistics.
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Figure 3.2: Avista and U.S. MSA Population Growth, 2007-2019
Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2018

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Non-farm employment growth averaged 2.7 percent per year between 1990 and 2007. However, Figure 3.4 shows that 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.
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. Figure 3.4: Avista and U.S. MSA Non-Farm Employment Growth, 2010-2019

5 Data Source: Bureau of Labor and Statistics. 6 Data Source: Bureau of Economic Analysis.
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Figure 3.5: MSA Personal Income Breakdown by Major Source, 2018
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 growth.
Although 57 percent of personal income is from net earnings, transfer payments 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 reflects an aging regional population, a surge of military veterans, and the
Great Recession; the later 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 in the 1970s to around 85 percent by the mid-1990s. The income ratio has not since
recovered.

7 Data Source: Bureau of Economic Analysis.
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Figure 3.6: Avista and U.S. MSA Real Personal Income Growth, 1970-2018
Five-Year Load Forecast Methodology
In non-IRP years, the retail and native load forecasts have a five-year time horizon. Avista
conducts the forecasts each spring and fall. The results feed into Avista’s revenue model, which converts the load forecast into a revenue forecast. In turn, the revenue forecast feeds Avista’s earnings model. In IRP years, the long-term forecast bootstraps off the five-year forecast by applying growth assumptions beyond year five. Overview of the Five-Year Retail Load Forecast The five-year retail load forecast is a two-step process. For most schedules in each class, there is a monthly use per customer (UPC) forecast and a monthly customer 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.
8 For schedules representing a single customer, where there is no customer count and for street lighting, Avista forecast total load directly without first forecasting UPC.
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Equation 3.1: Generating Schedule Total Load 𝐹𝐹(𝑘𝑘𝑘𝑘ℎ𝑡𝑡,𝑦𝑦𝑐𝑐+𝑗𝑗,𝑠𝑠) =𝐹𝐹(𝑘𝑘𝑘𝑘ℎ/𝐶𝐶𝑡𝑡,𝑦𝑦𝑐𝑐+𝑗𝑗,𝑠𝑠) × 𝐹𝐹(𝐶𝐶𝑡𝑡,𝑦𝑦𝑐𝑐+𝑗𝑗,𝑠𝑠)
Where:
• F(kWht,yc+j,s) = the forecast for month t, year j = 1,…,5 beyond the
current year, yc ,for schedule s.
• F(kWh/Ct,yc+j,s) = the UPC forecast.
• F(Ct,yc+j,s) = 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 𝑘𝑘𝑘𝑘ℎ/𝐶𝐶𝑡𝑡,𝑦𝑦,𝑠𝑠=𝛼𝛼𝑘𝑘𝑡𝑡,𝑦𝑦+𝛽𝛽𝑍𝑍𝑡𝑡,𝑦𝑦+ 𝜖𝜖𝑡𝑡,𝑦𝑦
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 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 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.
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 defines normal weather for the 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 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 1999 to 2018 period. The choice of a 20-year moving average for defining normal weather reflects several
factors. First, recent climate research from the National Aeronautics and Space Administration’s (NASA) Goddard Institute for Space Studies (GISS) shows a shift in temperature starting about 20 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 20 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 shows an upward shift in temperature starting about 20-years ago. A detailed discussion of this analysis is 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 average. This volatility can obscure longer-term trends and lead 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 forecast for five years 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% from 2026 to 2029; and then increase 1.5% 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 2020 IRP assumes elasticity to be -0.3%, based on long-run estimates from academic literature.11
This IRP generates IP forecasts from a regression using the GDP growth forecasts (GGDP). Figure 3.7 describes this process.
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 often difficult to obtain reliable elasticity estimates using data for an individual utility. Therefore, the Company has opted to rely on academic estimates using regionalized data covering multiple utilities. As theory would predict, the literature indicates that short-term elasticity is lower than long-term elasticity.
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Table 3.1: UPC Models Using Non-Weather Driver Variables
Schedule Variables Comment Washington:
Idaho:

The forecasts for GGDP reflect the average of forecasts from multiple sources. Sources include 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 that macroeconomic factors flow through UPC in the industrial schedules. This
reflects the relative stability of industrial customer growth over the business cycle. Figure 3.7: Forecasting IP Growth

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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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 autoregressive integrated moving average (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 schedule customer counts, the dependent variable. Because the customer counts in most 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 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 users 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 Residential
12 Data Source: U.S. Federal Reserve and Avista records. 13 Figure 3.8 excludes one large industrial customer with significant load volatility.
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Schedule 1 customers become drivers to generate customer forecasts for Commercial Schedule 11 customers.
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. Table 3.2: Customer Growth Correlations, January 1998 – December 2018
Customer Class (Year-over-Year) Residential Commercial Industrial Streetlights

Figure 3.9 demonstrates population growth as 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 in Washington and Idaho. If the growth rates generated from this approach differ from forecasted population growth, the forecasts adjust to match forecasted
population growth. Figure 3.10 summarizes the forecasting process for population growth
for use in Residential Schedule 1 customers. 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.
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Figure 3.10: Forecasting Population Growth
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. The forecasting models
for regional population growth are in Figure 3.10.
The employment growth forecasts (the average of Avista and IHS forecasts) become inputs 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 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.

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; Kootenai, ID; and Jackson, OR.
•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
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IRP Long-Run Load Forecast

The Basic Model
The long-run load forecast extends the five-year projection out to 2045. It includes the electric vehicle (EV) fleets and residential rooftop photovoltaic solar (PV). The long-run modeling approach starts with Equation 3.3. Equation 3.3: Residential Long-Run Forecast Relationship
ℓ𝑦𝑦=𝑐𝑐𝑦𝑦+𝑢𝑢𝑦𝑦
Where:
• ℓy = residential load growth in year y.
• cy = residential customer growth in year y.
• uy = UPC growth in year y. 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 assumptions about the long-run relationship between residential,
commercial, and industrial classes, as documented below. 1. As noted earlier, long-run residential and commercial customer growth rates are linked, consistent with historical growth patterns that show 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 0.7 percent, with a gradual 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
assumed that annual commercial customer growth is 0.78 times residential customer
growth. This number is the median ratio of commercial customer growth to residential customer growth since 2005. The annual average growth rate of commercial customers after 2025 is approximately 0.5%. The annual industrial customer growth rate assumption is -0.3% after 2025, which is equivalent to a decline of four industrial
customers a year out to 2045. This assumption reflects an ongoing long-run decline
in industrial customers. 2. Commercial load growth follows changes in residential load growth. This positive correlation assumption is consistent with the high historical correlation between
residential and commercial load growth. The connection, based on a linear regression
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.
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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 0.29
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 set at -0.3 percent after 2025 and streetlight load growth at 0 percent after 2025. Both
growth rates are in the range of historical norms and forecasted growth trends from the five-year model. 4. As noted earlier, the assumption in the five-year forecast for this IRP is for RAP to be constant out to 2025; increase at 1 percent between 2026 and 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 2020 IRP assumes own-price elasticity to be -0.3 percent, based on long-run estimates from academic literature.
5. Avista estimates 800 Electric Vehicles (EV) in its service area through 2019. The forecasted rate of adoption over the 2020-2045 period uses a weighted average of the EV forecast provided by Avista’s EV management team. This forecast reflects a low, middle, and high forecast for EVs in our electric service area. The low forecast predicts 45,000 EVs by 2045; the middle predicts 100,000; and the high predicts 250,000. The
final 2045 forecast used for the IRP weights the low forecast at 50 percent, the middle at 30 percent weight; and the high with a 20 percent weight. Therefore, the IRP forecast for 2040 is 0.50 x 45,000 + 0.30 x 100,000 + 0.20 x 250,000 = 102,500 EVs. Between 2020 and 2045, the implied growth rate is 19 percent, which puts total EVs in 2045 as 102,500. The forecast assumes each EV uses 3,500 kWh per year.
6. Rooftop PV penetration, measured as the share of PV residential customers to total residential customers, continues to grow at present levels in the forecast. The average PV system is forecast at the current median of 7.0 kW (DC) and a 13 percent capacity factor, or about 7,800 kWh per year per customer. The forecast assumes this median
system size will increase 1 percent annually to about 10,100 kWh per year per customer in 2045. The IRP assumes the penetration rate (share of residential customers) 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 PV penetration will increase from 0.25 percent in
2019 to about 2 percent in 2037. Although not directly calculated, the impact of PV penetration for commercial customers is indirectly accounted for by the assumed positive correlation between residential and commercial UPC.
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Figure 3.11: Long-Run Annual Residential Customer Growth
Native Load Scenarios with Low/High Economic Growth The high and low load scenarios use population growth Equations 3.6 and 3.7, holding long-run U.S. employment growth constant at 0.6 percent (an IHS forecast), but varying
MSA employment growth at higher and lower levels to gauge the impacts on population growth and utility loads. See Table 3.3. The high/low range for growth in service area employment reflects historical employment growth variability. Simulated population growth is a proxy for residential and customer growth in the long-run forecast model, and produces the high and low native load forecasts shown in Figure 3.12.
Table 3.3: High/Low Economic Growth Scenarios (2020-2045)
Economic Growth Annual U.S. Employment Growth (percent) Employment Growth (percent)Growth (percent)Expected Case 0.60 0.90 0.78
High Growth 0.60 1.80 1.20
Low Growth 0.60 0.60 0.60

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Figure 3.12: Average Megawatts, High/Low Economic Growth Scenarios
Table 3.4 is the average annual load growth rate over the 2020-2045 period. The low growth scenario predicts a slight load decline over 2025-2041.
Table 3.4: Load Growth for High/Low Economic Growth Scenarios (2020-2045)
Economic Growth Average Annual Native Load Growth (percent)
Expected Case 0.30 High Growth 0.60
Low Growth 0.00
Long-Run Forecast Residential Retail Sales Focusing on residential kWh sales, Figure 3.13 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 2019 Annual Energy Outlook. Both Avista’s and EIA’s
forecasts show positive UPC growth in the early 2040s. The 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 growth reflects the impact of EVs.

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Figure 3.13: UPC Growth Forecast Comparison to EIA
Figure 3.14 shows the EIA and the residential load growth forecasts. Avista’s forecast is
higher in the 2020-2029 period, reflecting an assumption that service area population
growth will be stronger than the U.S. average, consistent with government and IHS forecasts for the far west and Rocky Mountain regions where Avista’s service territory is located. Figure 3.14: Load Growth Comparison to EIA

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Monthly Peak Load Forecast Methodology
The Peak Load Regression Model The peak load forecast helps Avista determine the amount of resources necessary to
meet peak demand. In particular, Avista must build generation capacity to meet winter
and summer peak periods. Looking forward, the highest peak loads are 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. On a planning basis where we expect extreme weather to occur in the winter, peak loads occur
in the winter throughout the IRP timeframe. Equation 3.9 shows the current peak load
regression model. Equation 3.4: Peak Load Regression Model ℎ𝑀𝑀𝑘𝑘𝑑𝑑,𝑡𝑡,𝑦𝑦𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛=𝜆𝜆0 +𝜆𝜆1𝐻𝐻𝐻𝐻𝐻𝐻𝑑𝑑,𝑡𝑡,𝑦𝑦+𝜆𝜆2(𝐻𝐻𝐻𝐻𝐻𝐻𝑑𝑑,𝑡𝑡,𝑦𝑦)2+𝜆𝜆3𝐻𝐻𝐻𝐻𝐻𝐻𝑑𝑑−1,𝑡𝑡,𝑦𝑦+𝜆𝜆4𝐶𝐶𝐻𝐻𝐻𝐻𝑑𝑑,𝑡𝑡,𝑦𝑦 + 𝜆𝜆5𝐶𝐶𝐻𝐻𝐻𝐻𝑑𝑑,𝑡𝑡,𝑦𝑦𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻+ 𝜆𝜆6𝐶𝐶𝐻𝐻𝐻𝐻𝑑𝑑−1,𝑡𝑡,𝑦𝑦+𝜙𝜙1𝐺𝐺𝐻𝐻𝐺𝐺𝑡𝑡.𝑦𝑦−1+𝜙𝜙2(𝐻𝐻𝑆𝑆𝑆𝑆𝑆𝑆,2014↑∗𝐺𝐺𝐻𝐻𝐺𝐺𝑡𝑡.𝑦𝑦−1) +𝝎𝝎𝑾𝑾𝑾𝑾𝑾𝑾𝒅𝒅,𝒕𝒕,𝒚𝒚+𝝎𝝎𝑺𝑺𝑾𝑾𝑾𝑾𝒕𝒕,𝒚𝒚+𝜔𝜔𝑂𝑂𝑂𝑂𝐻𝐻𝑆𝑆𝑛𝑛𝑀𝑀 2005=1+𝜖𝜖𝑑𝑑,𝑡𝑡,𝑦𝑦 𝑓𝑓𝑓𝑓𝑓𝑓 𝑡𝑡,𝑦𝑦=𝐽𝐽𝑢𝑢𝐽𝐽𝐽𝐽 2004 ↑ Where:
• hMWd,t,ynetpeak = 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.
• HDDd,t,y and CDDd,t,y = heating and cooling degree days the day before the
peak.
• (HDDd,t,y)2 = squared value of HDDd,t,y.HDDd−1,t,y and CDDd−1,t,y = heating
and cooling degree days the day before the peak.
• CDDd,t,yHIGH = maximum peak day temperature minus 65 degrees.16
• GDPt.y−1 = extrapolated level of real GDP in month t in year y-1.
• (𝐻𝐻𝑆𝑆𝑆𝑆𝑆𝑆,2014↑∗𝐺𝐺𝐻𝐻𝐺𝐺𝑡𝑡.𝑦𝑦−1) 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 3.4 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
16 This term provides a better model fit than the square of CDD.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 51 of 259
out N years by using forecasted levels of GDP as shown in Equation 3.3.17 All other factors besides GDP remain constant to determine the impact of GDP on peak load. For
winter, this is defined as the forecasted series W: 𝑘𝑘= {𝐹𝐹(ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊),𝐹𝐹(ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+2𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊),…,𝐹𝐹(ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+𝑊𝑊𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊)}
For summer, this is defined as the forecasted series S:
𝑆𝑆= {𝐹𝐹(ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆),𝐹𝐹(ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+2𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆),…,𝐹𝐹(ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+𝑊𝑊𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡 𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆)}
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.):

𝑘𝑘𝐻𝐻= {𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊),𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+2𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊),…,𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+𝑊𝑊𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊)}

𝑆𝑆𝐻𝐻= {𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆),𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+2𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆),…,𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+𝑊𝑊𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆) }
In Equation 3.5, 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. The following section describes this process. Simulated Extreme Weather Conditions with Historical Weather Data
Equation 3.5 generates a series of simulated extreme peak load values for heating degree
days. Equation 3.5: Peak Load Simulation Equation for Winter Months ℎ𝑀𝑀𝑘𝑘�𝑡𝑡,𝑦𝑦𝑊𝑊=𝑎𝑎+𝜆𝜆1�𝐻𝐻𝐻𝐻𝐻𝐻𝑡𝑡,𝑦𝑦,𝑆𝑆𝐻𝐻𝑊𝑊 +𝜆𝜆2�(𝐻𝐻𝐻𝐻𝐻𝐻𝑡𝑡,𝑦𝑦,𝑆𝑆𝐻𝐻𝑊𝑊 )2 𝑓𝑓𝑓𝑓𝑓𝑓 𝑡𝑡=𝐽𝐽𝑎𝑎𝐽𝐽,…,𝐻𝐻𝐽𝐽𝑐𝑐 𝑖𝑖𝑓𝑓 𝑚𝑚𝑎𝑎𝑚𝑚𝑖𝑖𝑢𝑢𝑚𝑚 𝑎𝑎𝑎𝑎𝑎𝑎.𝑡𝑡𝐽𝐽𝑚𝑚𝑡𝑡<65 𝑎𝑎𝐽𝐽𝑎𝑎 𝑦𝑦=1890,…,𝑦𝑦𝑐𝑐 Where:
• hMW�t,yW = 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.

17 Forecasted GDP is generated by applying the averaged GDP growth forecasts used for the employment and industrial production forecasts discussed previously.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 52 of 259
Similarly, the model for cooling degree days is:
Equation 3.6: Peak Load Simulation Equation for Summer Months ℎ𝑀𝑀𝑘𝑘�𝑡𝑡,𝑦𝑦𝑆𝑆=𝑎𝑎+𝜆𝜆4�𝐶𝐶𝐻𝐻𝐻𝐻𝑡𝑡,𝑦𝑦,𝑆𝑆𝑀𝑀𝑀𝑀 𝑓𝑓𝑓𝑓𝑓𝑓 𝑡𝑡=𝐽𝐽𝑎𝑎𝐽𝐽,…,𝐻𝐻𝐽𝐽𝑐𝑐 𝑖𝑖𝑓𝑓 𝑚𝑚𝑎𝑎𝑚𝑚𝑖𝑖𝑢𝑢𝑚𝑚 𝑎𝑎𝑎𝑎𝑎𝑎.𝑡𝑡𝐽𝐽𝑚𝑚𝑡𝑡>65 𝑎𝑎𝐽𝐽𝑎𝑎 𝑦𝑦=1890,…,𝑦𝑦𝑐𝑐 Where:
• hMW�t,yS = 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
3.10 and 3.11 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 3.7 and 3.8 show the average for each month. Equation 3.7: Current Year Peak Load for Winter Months
𝐹𝐹�ℎ𝑀𝑀𝑘𝑘𝑡𝑡,𝑦𝑦𝑐𝑐𝑊𝑊�=1(𝑦𝑦𝑐𝑐−1890)+ 1 � ℎ𝑀𝑀𝑘𝑘�𝑡𝑡,𝑦𝑦𝑊𝑊𝑦𝑦𝑐𝑐𝑦𝑦=1890 𝑓𝑓𝑓𝑓𝑓𝑓 𝐽𝐽𝑎𝑎𝑐𝑐ℎ ℎ𝐽𝐽𝑎𝑎𝑡𝑡𝑖𝑖𝐽𝐽𝑎𝑎 𝑚𝑚𝑓𝑓𝐽𝐽𝑡𝑡ℎ 𝑡𝑡 𝑤𝑤ℎ𝐽𝐽𝑓𝑓𝐽𝐽 𝑚𝑚𝑎𝑎𝑚𝑚𝑖𝑖𝑢𝑢𝑚𝑚 𝑎𝑎𝑎𝑎𝑎𝑎.𝑡𝑡𝐽𝐽𝑚𝑚𝑡𝑡<65 Equation 3.8: Current Year Peak Load for Summer Months 𝐹𝐹�ℎ𝑀𝑀𝑘𝑘𝑡𝑡,𝑦𝑦𝑐𝑐𝑆𝑆�=1(𝑦𝑦𝑐𝑐−1890)+ 1 � ℎ𝑀𝑀𝑘𝑘�𝑡𝑡,𝑦𝑦𝑆𝑆𝑦𝑦𝑐𝑐𝑦𝑦=1890 𝑓𝑓𝑓𝑓𝑓𝑓 𝐽𝐽𝑎𝑎𝑐𝑐ℎ 𝑐𝑐𝑓𝑓𝑓𝑓𝑐𝑐𝑖𝑖𝐽𝐽𝑎𝑎 𝑚𝑚𝑓𝑓𝐽𝐽𝑡𝑡ℎ 𝑡𝑡 𝑤𝑤ℎ𝐽𝐽𝑓𝑓𝐽𝐽 𝑚𝑚𝑎𝑎𝑚𝑚𝑖𝑖𝑢𝑢𝑚𝑚 𝑎𝑎𝑎𝑎𝑎𝑎.𝑡𝑡𝐽𝐽𝑚𝑚𝑡𝑡>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:

𝐹𝐹�ℎ𝑀𝑀𝑘𝑘𝑡𝑡,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊�=𝐹𝐹�ℎ𝑀𝑀𝑘𝑘𝑡𝑡,𝑦𝑦𝑐𝑐𝑊𝑊� ∗[1 +𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑊𝑊)]
𝐹𝐹�ℎ𝑀𝑀𝑘𝑘𝑡𝑡,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆�=𝐹𝐹�ℎ𝑀𝑀𝑘𝑘𝑡𝑡,𝑦𝑦𝑐𝑐𝑆𝑆� ∗[1 +𝐹𝐹(𝐺𝐺ℎ𝑀𝑀𝑘𝑘𝑑𝑑𝑀𝑀𝑀𝑀𝑀𝑀,𝑡𝑡𝑀𝑀𝑀𝑀𝑀𝑀,𝑦𝑦𝑐𝑐+1𝑊𝑊𝑊𝑊,𝑛𝑛𝑛𝑛𝑡𝑡𝑛𝑛𝑛𝑛𝑛𝑛𝑛𝑛,𝑆𝑆)]

The finalization of the peak load forecast occurs when the forecasted peak loads of two
large industrial customers and EVs, excluded from the Equation 3.7 and 3.8 estimations, are added back in.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 53 of 259
Table 3.5 shows estimated peak load growth rates with and without the two large industrial customers. Figure 3.15 shows the forecasted time path of peak load out to 2045,
and Figure 3.16 shows the high/low bounds based on a one-in-20 event (95 percent confidence interval) using the standard deviation of the simulated peak loads from Equations 3.7 and 3.8. Table 3.5: Forecasted Winter and Summer Peak Growth, 2020-2045
Category Winter (Percent) Summer (Percent)

Table 3.6 shows how the summer peak forecast grows faster than the winter peak. Under
current growth forecasts, the orange summer line in Figure 3.15 will get close to the blue
winter line by 2045. Figure 3.16 shows that the winter high/low bound considerably larger than summer, and reflects a greater range of temperature anomalies in the winter months. Table 3.6 shows the energy and peak forecasts.
Figure 3.15: Peak Load Forecast 2020-2045

Me
g
a
w
a
t
t
s
Winter Peak
Summer Peak
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 54 of 259
Figure 3.16: Peak Load Forecast with 1 in 20 High/Low Bounds, 2020-2045

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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 55 of 259
Table 3.6: Energy and Peak Forecasts
Year Energy (aMW) Winter Peak (MW) Summer Peak (MW)

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 56 of 259

Page Intentionally Left Blank
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 57 of 259
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 hydroelectric at 50 percent, followed by natural gas-fired resources at 36 percent. On an energy capability basis, natural gas-fired generation can produce more energy, at 41 percent,
than hydroelectric at 35 percent because it is not constrained by fuel limitations. In any
given year, the resource mix will change depending on streamflow conditions and market prices. Figure 4.1: 2020 Avista Capability and Energy Fuel Mix

Winter Peak Capability Annual Energy Capability
Section Highlights
• Hydroelectric represents about half of Avista’s winter generating capability.
• Natural gas-generation portfolio.
• Since the 2017 IRP, Avista signed PPAs for new solar and wind projects.
• Twelve percent of Avista’s generating potential is biomass, wind, solar, or refuse.
• Avista’s net metering program includes 1,046 customers with 8.6 megawatts of their own generation.
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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 the environmental attributes from renewable energy credit (REC) sales3. Figure 4.2 shows Avista’s 2018 fuel mix disclosure from the Washington State Department of Commerce as of November 8, 2019. Idaho customer’s fuel mix is nearly identical to this report with the exception of purchases 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. An example of REC transfers between states entails RECs used to comply with Washington’s Energy Independence Act (EIA). In this case, Idaho transfers its share of qualifying RECs to Washington customers in exchange for a
reduction in rates for Idaho customers. This fuel mix disclosure includes regionally assigned fuel mix where Avista sells RECs to others. Figure 4.2: 2018 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
1 http://www.commerce.wa.gov/wp-content/uploads/2019/12/2018-Preliminary-Disclosure-Data-03122019.pdf 2 For 2018, the region is approximately 46 percent hydroelectric, 23 percent coal, 15 percent natural gas, 3 percent nuclear, 8 percent wind, and 4 percent other.
3 In 2018, Avista sold 56 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.
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configuration and the current mechanical state of the facility. This capacity is often higher than the nameplate rating for hydroelectric developments because of plant
upgrades and favorable head or streamflow conditions. The nameplate, or installed capacity, is the capacity of a plant as rated by the manufacturer. All six hydroelectric developments on the Spokane River connect directly to the Avista electrical system. Avista also provides historical operating data for each of the projects for 2014 through 2018 in Appendix C – Historical Generation Operating Data (Confidential).
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. Chapter 9 - Supply-Side Resource Options provides details about potential modernization options under consideration at Post Falls. 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 nameplate unit with a 10.26 MW maximum capacity rating. 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 14.8 MW nameplate rating and 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 details about potential 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 of on-peak capacity and have a 32.0 MW nameplate rating.
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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. The plants operate under a FERC license through 2046. Both hydroelectric projects on the Clark
Fork River connect 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
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 incremental generation from the upgrades qualifies for the EIA. Cabinet Gorge
Cabinet Gorge started generating power in 1952 with two units, and added two
additional generators the following year. Upgrades to units 1 through 4 occurred in 1994, 2004, 2001, and 2007. The current maximum on-peak plant capacity is 270.5 MW; it has a nameplate rating of 265.2 MW. The incremental generation from the upgrades qualifies for the EIA.
Total Hydroelectric Generation
Avista’s hydroelectric plants have 1,080 MW of on-peak 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
System Location Nameplate Capacity Capability 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

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Thermal Resources
Avista owns seven thermal generation assets located across the Northwest. The resources provide dependable energy and capacity serving base-load and peak-load obligations. Table 4.2 summarizes resources by fuel type, online year, remaining life,
book value at the end of 2018, and remaining accounting life. Appendix C provides
operating details for these facilities between 2014 and 2018. 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.
Table 4.2: Avista-Owned Thermal Resources
Project Name Location Fuel Type Start Date Remaining Design Life Book Value (mill. $) Book Life (years)
Table 4.3: Avista-Owned Thermal Resource Capability
Project Name Winter Maximum Maximum Capacity (MW) Outage Rate
Colstrip 3 111 111 123.5 9.3
Colstrip 4 111 111 123.5 9.3
Rathdrum (2 units) 176 130 166.5 5.0
Northeast (2 units) 66 42 61.2 5.0
Boulder Park (6 units) 24.6 24.6 24.6 13.7
Coyote Springs 2 317.5 286 287.3 2.6 Kettle Falls 47 47 50.7 2.4
Kettle Falls CT 11 8 7.5 5.0

Colstrip Units 3 and 4 The Colstrip plant, located in eastern Montana, consists of four 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.
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. Avista has received approval for the 2025 life in Washington, but has not received authorization in Idaho to recover all costs through 2027.
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Talen Energy Corporation operates the facilities on behalf of the six owners. Avista has no ownership interest in Units 1 or 2 (closed in January 2020), but 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.
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 or fuel oil, 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 per year. Boulder Park
The Boulder Park project entered service in the Spokane Valley in 2002 and 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. 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; it has a maximum capacity of 317.5 MW in the winter and 285 MW in the summer with duct
burners. The nameplate rating of the plant is 287.3 MW. Kettle Falls Generation Station and Kettle Falls Combustion Turbine The Kettle Falls Generating Station, a woody biomass facility, 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 biomass steam plant uses waste wood products (hog fuel) from area mills and forest slash, but can also burn natural gas. 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.
The wood-fired portion of the plant has a maximum capacity of 50 MW, and its nameplate rating is 50.7 MW. The plant typically operates between 45 and 47 MW because of fuel conditions that change depending on the moisture content of the hog
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fuel. The plant’s capacity increases to 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 resource can be limited in the winter when the natural gas pipeline is capacity constrained. For IRP modeling, the CT does not run when temperatures fall below zero7. This operational assumption reflects natural gas availability limits on the plant when local natural gas distribution demand is highest. Small Avista-Owned Solar
Avista has three small projects of its own. The first solar project was three kilowatts on
its corporate headquarters as part of the Solar Car initiative. The solar production
helped power two electric vehicles in the corporate fleet. Avista installed a 15-kilowatt solar system in Rathdrum, Idaho to supply Buck-A-Block, a voluntary program allowing customers to purchase green energy. The 423-kW Avista Community Solar project, located at the Boulder Park property, entered service in 2015.
Table 4.4: Avista-Owned Solar Resource Capability
Project Name Project Location Project Capacity (kW-DC)
Total 441
Power Purchase and Sale Contracts
Avista uses purchase and sale arrangements of varying lengths to meet a portion of its
load requirements. Contracts provide many benefits, including environmentally low-impact and low-cost hydroelectric and wind power. This chapter describes the contracts in effect during the timeframe of the 2020 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 and ensured 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 four of these projects
“at cost.” Avista now competes in capacity auctions to retain the rights of these expiring contracts. The Mid-Columbia contracts in Table 4.5 provide energy, capacity and reserve capabilities; in 2019, the contracts provided approximately 225 MW of capacity and 142 aMW of energy.
7 Avista is reviewing its policies and may restrict the CT’s use when the pipeline is at lower pressures then the current standard. This change could further reduce the plant from producing power in winter months.
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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
16, 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 negotiations will determine the future of the treaty. This IRP does not model alternative outcomes for the treaty negotiations, because it will not likely affect long-term resource acquisitions and we cannot speculate on future wholesale
electricity market impacts of the treaty at this time. Table 4.5: Mid-Columbia Capacity and Energy Contracts8
Counter Party Share (%) On-Peak Capability Energy (aMW)
Grant PUD Priest Rapids 3.79 Dec-2001 Dec-2052 36 19.5
Grant PUD Wanapum 3.79 Dec-2001 Dec-2052 39 18.5
Chelan PUD Rocky Reach 5.0 Jan-2016 Dec-2030 56 35.9
Chelan PUD Rock Island 5.0 Jan- 2016 Dec-2030 25 19.0 Douglas PUD Wells 12.469 Oct- 2018 Dec-2023 79 54.7
Canadian Entitlement -10 -5.6
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. Appendix C includes operating details of these projects. Avista takes the
energy as produced and does not control the output of any PURPA resources.
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.
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Table 4.6: PURPA Agreements
End Date (MW) Gen. History
Meyers Falls Hydro Kettle Falls, WA 12/2020 1.30 1.10
Spokane Waste to Energy Waste Spokane, WA 12/2022 18.00 13.80
Spokane County Digester Biomass Spokane, WA 8/2021 0.26 0.13
Plummer Saw Mill Wood Waste Plummer, ID 12/2020 5.80 3.66
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 17.60 6.30
Big Sheep Creek Hydro Hydro Northport, WA 6/2021 1.40 0.92
Ford Hydro LP Hydro Weippe, ID 6/2022 1.41 0.42
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 0.38
Clearwater Paper Biomass Lewiston, ID 12/2023 90.20 44.98
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. Avista has the option to purchase the project after 10 years. Commercial operation began in December 2012. The project is EIA-qualified and directly connected to Avista’s transmission system between Rosalia and Oaksdale, Washington in Whitman County.
Rattlesnake Flats Wind Power Purchase Agreement Between the 2017 IRP and this IRP process, Avista identified an opportunity to procure low cost renewable PPA at prices close to the energy market. This opportunity maintains Avista’s lower power costs and assists in meeting CETA requirements and
corporate clean energy goals. Avista released an RFP for 50 aMW in 2018. The project selected from this process was a 20-year PPA for the 146 MW Rattlesnake Flat wind project with an expected net output of 434,500 MWh (49.6 aMW) each year. The project
10 Energy estimate is net of the city of Spokane’s pumping load.
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schedule is to be online in the second half of 2020, and it is located east of Lind, Washington in Adams County.
Adams-Nielson Solar Power Purchase Agreement Avista signed a 20-year PPA for Washington State’s largest commercial solar project in 2017. The project is an 80,000 panel single axis solar facility capable of delivering 19.2 MW of AC power. The project is north of Lind, Washington in Adams County. The
project began generating in December 2018. The project serves for Avista’s Solar Select program. Solar Select allows commercial customers to purchase the 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.
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 283 233 218
Palouse Wind Purchase Wind 2042 5.3 5.3 36.2 Rattlesnake Flats Purchase Wind 2040 7.3 7.3 49.6
Adam-Nielson Purchase Solar 2038 0.4 10.2 5.6
Nichols Pumping Sale System 202311 -5 -5 -5.0
Morgan Stanley Sale Clearwater Paper 2023 -46 -46 -44.9
Douglas PUD Sale System 2023 -48 -48 -48.0
Customer-Owned Generation
Avista has 1,140 customer-installed net-metered generation projects on its system as of the end of November 2019, representing a total installed capacity of 8.6 MW-DC. Ninety-two percent of installations are in Washington, with most located in Spokane
County. Figure 4.3 shows annual net metering customer additions. Solar is the primary
net metered technology; the remaining is a mix of wind, combined solar and wind systems, and biogas. The average system size is 7.5 kilowatts. Avista has seen a drop in solar system installs in 2019 due to reduced subsidy rates in Washington. In Idaho, solar install rates continue to increase each year without a major subsidy, but total only
94 as compared to Washington with over 1,000. If the number of net-metering
customers continues to increase, Avista may need to adjust rate structures for customers who rely on the utility’s infrastructure but do not contribute financially for infrastructure costs.
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 uses the GTN pipeline owned by TC Energy (formally TransCanada) to transport natural gas to our natural gas-fired generators. This pipeline runs between Alberta, Canada and the California/Oregon border at Malin. Avista’s rights on the system are for 60,592 dekatherms per day between the AECO area and Stanfield and another 26,388 dekatherms per day between Malin and Stanfield. This total is 60,592 dekatherms of
rights per day. 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 131,760 dekatherms in one day of the top five historical natural gas burn days, as shown in Table 4.8.
Avista is short on natural gas capacity and uses the short-term transportation market to relieve the shortfall on a day-to-day basis. Historically, these rights were available because the GTN pipeline was not fully subscribed. Recently, natural gas producers have purchased all of the remaining rights on the system to transport their supply south and take advantage of higher prices in the U.S. compared to Canada. Avista plans to
continue to acquire its remaining natural gas through the daily market. If this market begins to tighten, Avista will need to invest in onsite fuel storage.
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Figure 4.4: Avista’s Natural Gas Pipeline Rights
Table 4.8: Top five Historical Peak Natural Gas Usage (Dekatherms)
Date Boulder Park Springs 2 Total Burn Rights
8/9/2018 5,387 47,668 40,364 38,340 131,760 60,592 (71,168)
7/22/2018 5,452 47,057 43,909 35,016 131,434 60,592 (70,842)
8/8/2018 5,289 47,571 40,841 36,499 130,199 60,592 (69,607)
7/25/2018 3,991 48,201 43,050 34,348 129,591 60,592 (68,999)
8/13/2018 5,352 48,458 40,094 35,491 129,395 60,592 (68,803)

AECO
Lancaster 49,000
Rathdrum 43,600
Boulder 5,400
98,000 DTh/Day
Coyote Springs
53,550 DTh/Day Stanfield
Malin
Pipeline Capacity
60,592 DTh/Day
Pipeline Capacity
26,388 DTh/Day
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Resource Environmental Requirements and Issues
The generation of electricity has environmental impacts and is subject to regulation by federal, state, and local authorities. The generation, transmission, distribution, service, and storage facilities in which we have ownership interests are designed, operated, and
monitored to maintain compliance with applicable environmental laws. Furthermore,
Avista conducts periodic reviews and audits of our facilities and operations to ensure 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 may:
• Increase operating costs of generation;
• Increase the time and costs to build new generation;
• Require modifications to existing plants;
• Require curtailment or shut down of generation;
• Reduce the amount of generation available from 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 in sections describe applicable 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 CAA
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, Northeast CT, and other operations require minor source permits or simple source registration permits to operate. These requirements can change as the CAA or other regulations change and agencies issue new permits. A number of specific regulatory
programs authorized under the CAA can 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.
In December 2018, the EPA proposed to revise earlier MATS findings and make a new determination that is not “appropriate and necessary” to regulate hazardous air pollutants from power plants. The EPA proposes this conclusion based on a new cost/benefit analysis. Because Colstrip has already implemented applicable MATS
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control measures, and because changes to the rule are still under review, it is unclear what, if any, impact the EPA’s most recent proposal will have.
Montana Mercury Rule Montana established a site wide Mercury cap in 2010, requiring Mercury to be below 0.9 lbs per Tbtu. Colstrip installed a mercury oxidizer/sorbent injection system. The Montana Department of Environmental Quality (MDEQ) recently reviewed the
equipment and concurred with the plant’s equipment. Currently Avista’s share of units 3 and 4 operate at 0.8 lb per Tbtu range. There is no indication that 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. 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 regarding coal combustion residuals (CCRs), also known as coal combustion byproducts or coal ash. The CCR rule has been the subject
of 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
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.
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Particulate Matter (PM) Issues Particulate Matter (PM) is the term 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 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 that are 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 has ownership and/or operational control for the following thermal electric generating facilities that produce PM: Boulder Park, Colstrip, Coyote Springs 2, Kettle Falls, Lancaster, Northeast and Rathdrum. Table 4.9 shows each of these generating stations, 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. Table 4.9: Avista Owned and Controlled PM Emissions
Generating 2.5NAAQS 10NAAQS Permit
Boulder Park Attainment Maintenance Minor Source Pipeline Natural Gas
Colstrip Attainment Non-Attainment Major Source Title V OP Fluidized Bed Wet Scrubber
Coyote Springs 2 Attainment Attainment Major Source Title V OP Pipeline Natural Gas, Air filters Kettle Falls Attainment Attainment Major Source
Title V OP
Multi-clone collector,
Electrostatic Precipitator Lancaster Attainment Attainment Major Source
Title V OP
Pipeline Natural Gas, Air
filters
Northeast Attainment Maintenance Minor Source Pipeline Natural Gas, Air filters
Rathdrum Attainment Attainment Major Source Title V OP Pipeline Natural Gas, Air filters

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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 hydroelectric project on the Clark Fork River 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 on the lower Clark Fork River, consistent with requirements of the 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, so we have developed and follow an avian protection plan. Climate Change - Federal Regulatory Actions
The EPA released the final version of the Affordable Clean Energy (ACE) rule in June 2019 as the replacement for the Clean Power Plan (CPP). EPA’s final rule does not contain any final action on the proposed modifications to the new source review (NSR) program that would provide coal-fired power plants more latitude to make efficiency improvements without triggering pre-construction permit requirements. The final ACE
rule combines three distinct EPA actions. First, EPA finalizes the repeal of the CPP. Second, the EPA finalizes the ACE rule; which comprises EPA’s determination of the Best System of Emissions Reduction (BSER) for existing coal-fired power plants and establishment of the procedures that will govern States’ promulgation of standards of performance for existing EGUs within their borders. EPA sets the final BSER as heat
rate efficiency improvements (HRI) based on a range of “candidate technologies” to apply to a plant's operating units and requires each State to determine the technologies applicable to each coal-fired unit based on consideration of remaining useful plant life. Lastly, EPA finalizes a number of changes to the implementing regulations for the timing of State plans for this and future section 111(d) rulemakings. With respect to Colstrip,
the MDEQ would initiate the BSER evaluation process. Climate Change - State Legislation and State Regulatory Activities Washington and Oregon both adopted non-binding targets to reduce greenhouse gas emissions. Both states enacted targets 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.” However, neither state mandated specific reductions yet, but have enacted other targets to reduce greenhouse gas emissions. Washington State enacted Senate Bill 5116 or the Clean Energy Transformation Act (CETA). As stated
elsewhere in this IRP, the focus of the legislation is to reduce greenhouse gas emissions from specific sectors of the economy through direct regulation. CETA requires utilities to eliminate coal-fired resources from Washington retail rates by the end of 2025, achieve carbon neutrality by 2030 while meeting a minimum 80 percent of
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load through delivery of renewable or non-emitting resources to customers, and serve all retail load with renewable and non-emitting resources by 2045.
Washington and Oregon apply a greenhouse gas emissions performance standard (EPS) 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 CO2e pounds per MWh. The Washington State Department of Commerce reviews the standard every five years. In September 2018, it adopted a new standard 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. The EIA also requires
these utilities to meet biennial energy conservation targets beginning in 2012. The renewable energy standard increased from 3 percent in 2012 to 9 percent in 2016 and 15 percent in 2020. Failure to comply with renewable energy and efficiency standards could result in penalties of $50 per MWh or greater assessed against a utility for each MWh it is deficient in meeting a standard. We have met, and will continue to meet, the
requirements of the EIA through a variety of renewable energy generating means, including, but not limited to, some combination of hydroelectric 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. Colstrip
This section provides further details related to Colstrip. Colstrip was a four-unit coal
plant in Eastern Montana. Avista is partial owner in Units 3 and 4. A complete list of the ownership shares and sizes of the plant is in Table 4.10. Puget Sound Energy and Talen Energy shut down units 1 and 2 in early 2020. Washington’s CETA prohibits utilities from charging Washington retail customers with coal after 2025. Utilities failing
to comply may receive fines for each MWh delivered into the state after 2030. This
requirement applies to Avista, Puget Sound Energy, and PacifiCorp. Oregon (SB 1547) requires utilities to stop using coal by 2030, although there are carve outs through 2035. This law affects PacifiCorp and Portland General Electric.

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Figure 4.5: Overview of the Colstrip Area
Table 4.10: Colstrip Ownership Shares12
Unit 1 Unit 2 Unit 3 Unit 4 Total

Coal Contract
Colstrip is supplied fuel from the adjacent coal reserves under coal supply and transportation agreements that expired December 2019. Avista, along with four other owners, agreed to a contract extension with Rosebud Mine LLC to continue supplying the plant with coal. The new contract provides coal through December 31, 2025 with
options to extend the contract. The specific terms of the agreement are confidential, but
the prices and terms are consistent with the prices assumed in this IRP.
12 Puget Sound Energy announced an agreement on December 10, 2019 that it intends to sell its 185 MW share of Unit 4 to Northwestern Energy for $1 and enter into a PPA for 90 MW for up to five years. The transmission is also being included in the sale for an undisclosed price. Puget Sound Energy will still maintain responsibility for their current share of remediation and decommissioning costs. Northwestern Energy is seeking review of the proposed transaction by the Montana Utilities Commission,
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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 Rock Lake to serve as the Surge pond for the plant and as the water supply for the Town of Colstrip. From the Surge pond, 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 reused.
The plant uses three major areas for water and waste management. The first is the Plant Site Area, in which all units share use of the ponds, Avista is responsible for its share of these facilities. The second major area only for Units 3 and 4 is the Effluent Holding Pond (EHP) Area. 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. Figure 4.6 shows a map of the different storage areas at Colstrip.
Colstrip will covert to dry ash storage by the end of 2022. The master plan for site wide ash management is filed with the MDEQ-AOC13 and additional information regarding the 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 previously posted bonds for $5,841,000 on December 21, 2018 for cost assurance and an additional $383,713 on February 1, 2019 for the closure plan. Avista posted an additional $6,793,050 on February 1, 2019 related to Units 3 and 4 for
closure. These amounts are expected to be updated annually, increasing as clean-up plans are approved in the coming years and then decreasing over time as remediation activities are completed.
13 http://deq.mt.gov/DEQAdmin/mfs/ColstripSteamElectricStation. 14 https://www.talenenergy.com/ccr-colstrip/.
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Figure 4.6: Map of Water Storage
Colstrip Cost for IRP Modeling Avista provides many of the costs of Avista’s share of Colstrip in Table 4.11. These costs are the assumptions included in the plan and are subject to change. Scenarios regarding extending Colstrip operations beyond 2027 use these estimates as a starting point. Avista is not including costs related to the fuel or variable O&M costs due to its
sensitive market information regarding how the plant is dispatched. The cost included are the ongoing operations of the plant and the amortization of the existing and future capital expenditures. The CCR costs will extend to 2045. Avista anticipates a sharing ratio of 65 percent of these costs to be recovered by Washington and 35 percent by
Idaho. Table 4.10: Colstrip Costs Modelled in the IRP (millions)
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Total 40.3 32.3 32.9 37.8 34.7 8.0 7.2 3.5 3.1 3.1
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Post 2025 Considerations There are three primary drivers affecting operational and financial risks associated with
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 the Washington CETA. 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 after December 31, 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 by its terms on December 31, 2025, but can be extended up to December 31,
2029. If the coal supply agreement is extended beyond December 31, 2025, the parties will need to negotiate a new price for coal for the extended term. Section 3 of the Washington Clean Energy Transformation Act 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 by December 31, 2025.17
It is difficult to speculate on all potential scenarios associated with future Colstrip Unit 3 and 4 operations; however, in general, there are three likely scenarios for these units after December 31, 2025:
• 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; and
• the units will be shut down. If one or both units continue to operate after December 31, 2025, and Avista is an owner of the operating unit or units, there will be certain items that need to be addressed. First, Avista will need to evaluate its contractual obligations under the
existing ownership and operation agreement. Second, if Avista is required by contract to provide its share of the coal to operate the unit(s), Avista will need to either extend its existing coal supply agreement or make some other arrangement to obtain its share of the coal. Finally, Avista will need to determine how it is going to comply with the requirements of any applicable laws, including the Washington CETA.

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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5. Energy Efficiency

Avista began offering energy efficiency programs in 1978. These programs are all cost-effective strategies to reduce customer’s usage within the prevailing market and economic conditions. Recent programs with the highest impacts on energy savings include residential and non-residential prescriptive lighting, residential fuel efficiency, site-
specific lighting, and small business projects. Energy Efficiency programs regularly meet or exceed regional shares of the energy efficiency gains outlined by the Northwest Power and Conservation Council (NPCC).

Figure 5.1 illustrates Avista’s historical electricity conservation acquisitions. Avista has acquired 240 aMW of energy efficiency since 1978; however, the 18-year average measure life of the conservation portfolio means some measures no longer are reducing
load. The 18-year measure life accounts for the difference between the cumulative and online trajectories in Figure 5.1. Currently 155 aMW of energy efficiency serves customers, representing nearly 12.2 percent of 2018 load. Avista’s energy efficiency programs provide energy efficiency and education options to the residential, low income, commercial, and industrial customer segments. Program delivery includes prescriptive, site-specific, regional, upstream, behavioral, market transformation, and third-party direct install options. Prescriptive programs, or standard offerings, provide cash incentives for measures where the customer and equipment are
homogenous enough to reasonably qualify eligibility of both and deliver demonstrable savings. An example is the installation of qualifying high-efficiency heating equipment by an eligible customer. Prescriptive programs work in situations where uniform measures or offerings apply to large groups of similar customers and primarily occur in programs for residential and small commercial customers.
Site-specific programs, or customized offerings, provide cash incentives for cost-effective energy saving measures or equipment that are analyzed and contracted and do not meet prescriptive rebate requirements. Site-specific programs require customized services for commercial and industrial customers because of the unique characteristics of each of
their premises and processes. Other delivery methods build off these approaches, but may include upstream and mid-stream retail buy-downs of low cost measures, free-to-customer direct install programs, and coordination with regional entities for market transformation efforts. In addition to developing and delivering incentive offerings, Avista provides technical assistance to help educate and inform customers about various types
of efficiency measures.
Section Highlights
• Current Avista-sponsored energy efficiency reduces loads by nearly 12.2 percent, or 155 aMW.
• This IRP evaluated over 6,300 measure options covering all major end use equipment, as well as devices and actions to reduce energy consumption for this IRP.
• The 2020-21 Washington EIA penalty threshold is 59,948 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 third party to assist in developing a Conservation Potential Assessment (CPA) for this IRP. The study forms the basis for the energy efficiency portion of this plan. The CPA identifies the 20-year1 potential for energy efficiency and provides data on resources specific to Avista’s service
territory for use in the resource selection process, in accordance with the EIA’s energy
efficiency goals. The energy efficiency potential 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 in Appendix D of this IRP and the list of measure is in Appendix E.
AEG first developed estimates of technical potential, reflecting the adoption of all conservation measures, regardless of cost-effectiveness. The next step identified the achievable technical potential; this modifies the technical potential by accounting for
customer adoption constraints, using the Council’s Seventh Plan ramp rates. The
estimated achievable technical potential, along with associated costs, feed into the
PRiSM model to select the cost-effective measures. AEG took the following steps to assess and analyze energy efficiency and potential within Avista’s service territory. Figure 5.2 illustrates the steps of the analysis.
1 Avista extrapolates the 20-year data an extra five years for the full planning horizon of this IRP.
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Figure 5.2: Analysis Approach Overview
1. Characterize the Market: Categorizes energy consumption in the residential (including low-income customers), commercial, and industrial sectors. This
assessment uses utility and secondary data to characterize customers’ electricity
usage behavior in Avista’s service territory. AEG uses this assessment to develop energy market profiles describing energy consumption by market segment, vintage (existing or new construction), end use, and technology.
2. Baseline Projection: Develops a projection of energy and demand for electricity,
absent the effects of future conservation by sector and by end use, for the entire 20-
year study.
3. Measure Assessment: Identifies and characterizes energy efficiency measures appropriate for Avista, including regional savings from energy efficiency measures acquired through Northwest Energy Efficiency Alliance efforts.
4. Potential: Analyzes measures to identify technical and achievable technical
conservation potential.
Washington House Bill 1444 Appliance Standards The CPA incorporates newly enacted legislation for all jurisdictions when the information
is available. For this current CPA, Avista adjusted its Washington selections with guidance from House Bill 1444 (HB 1444) which provides minimum efficiency standards for several residential, commercial, and industrial measures. HB 1444 places minimum efficiency standards on general service lamps (LEDs), showerheads, commercial fryers,
commercial hot holding cabinets, and several other residential and non-residential
appliances.
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The structure of Avista’s Energy Efficiency program incentivizes customers to install and use high efficiency equipment. The minimum standards outlined in HB 1444 reduce the
overall potential for Avista’s conservation program since the opportunity for incentivizing customers would not result in participating in higher efficiency products since the high efficiency would be the only option. Including HB 1444 in Avista’s CPA reduces the overall potential for the state of Washington by 0.5 percent (32,000 MWh) through 2030 and 0.7 percent (43,000 MWh) by 2040. These minimum efficiency standards did not affect
Idaho’s service territory’s potential or energy efficiency. Market Segmentation The CPA divides Avista customers by state and by class. The residential class segments include single-family, multi-family, manufactured home, and low-income customers.2
AEG incorporated information from the Commercial Building Stock Assessment to break out the commercial sector by building type. Avista analyzed the industrial sector as a whole for each state. AEG characterized energy use by end use within each 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 the “business as usual” metric without future utility conservation 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 existing beyond the impact of these efforts. The baseline projection accounts for market changes including:
• customer and market growth;
• income growth;
• retail rates forecasts;
• trends in end use and technology saturations;
• 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 Seventh Power Plan, the Regional Technical Forum, and other measures applicable to Avista. The 6,400 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.
2 The low-income threshold for this study is 200 percent of the federal poverty level. Low-income information is available from census data and the American Community Survey data.
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Avista supplements energy efficiency activities by including potentials for distribution efficiency measures consistent with EIA conservation targets and the NPCC Seventh
Power Plan. Avista manages street light fixtures for many local and state governments. As an element of its 2013 Street Light Asset Management Plan, Avista's Asset Management group replaced approximately 21,640 high-pressure sodium fixtures, of which 15,148 are in
Washington, with comparable LED fixtures. This project began in in 2015, with the vast majority of lights replaced by the end of 2019. For 2020-2021, it is expected that a small number of outstanding lights will be converted, resulting in distribution efficiencies of 136 MWh in both 2020 and 2021.
Grid Modernization technology has been designed to improve the power grid's reliability and performance by optimizing the push and pull from supply and demand. Ultimately, these projects will move the region and nation closer to establishing a more efficient and effective electricity infrastructure that's expected to help contain costs, reduce emissions, incorporate more wind power and other types of renewable energy, increase power grid
reliability, and provide greater flexibility for consumers. The total estimated savings from feeder upgrades is 269 MWh in 2020 and 152 MWh is 2021. 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.3 The guide represents the most credible and comprehensive national industry standard practice for specifying energy efficiency potential. Specifically, two types of potential are in this study, as discussed below. Table 5.1 shows the CPA results for technical and achievable technical potential.
Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years)
2021 2022 2025 2030 2040
Technical Potential
Technical potential finds the most energy-efficient option commercially available for
each purchase decision, regardless of its cost. This theoretical case provides the broadest and highest definition of savings potential because it quantifies savings resulting if all current equipment, processes, and practices, in all market sectors, were
3 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
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replaced by the most efficient and feasible technology. Technical potential in the CPA is a “phased-in technical potential,” meaning only the portion of current equipment
stock at the end of its useful life is considered and changed out with the most efficient measures available. Non-equipment measures, such as controls and other devices (e.g., programmable thermostats) will phase-in over time, just like the equipment measures. Technical Achievable Potential Technical achievable potential is a subset of technical potential and represents the portion comprised of technically feasible reductions in load associated with applicable end-uses. It refines technical potential by applying customer participation rates to account for market barriers, customer awareness and attitudes, program maturity, and
other factors that may affect market penetration of energy efficiency measures. The customer participation rates use the NPCC Seventh Power Plan ramp rates. PRiSM Co-Optimization
Avista’s identifies achievable economic conservation potential by concurrently evaluating supply-side and demand-side resources together in Avista’s PRiSM model. In PRiSM, the energy efficiency resources compete with supply-side and demand response options to meet Avista resource deficits; although, energy efficiency measures benefit by receiving additional value streams as compared to other resources. These additional value streams
include 10 percent more energy and capacity benefits as compared to the supply-side resources. Energy efficiency also receives additional financial benefits by including financial savings from reducing line losses and avoided transmission and distribution costs. In Washington, an additional credit for reducing greenhouse gas emissions is also included.
Energy Efficiency Targets
Energy efficiency will lower system sales by an additional 138 aMW by 2040; this
translates into a 12.6 percent savings. The savings between states are similar to the share of load between states, as Idaho saves 37 percent of the saving potential as compared to Washington’s 63 percent. Figure 5.3 shows the total savings by state for selected years. Commercial and Residential customers provide a majority of the savings of the
three major customer classes. Each of these savings are broken-down between the
states in Figure 5.4 and Figure 5.5.
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Figure 5.3: Conservation Potential Assessment - 20-Year Cumulative MWh
Figure 5.4: Idaho Energy Efficiency Savings by Segment

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Figure 5.5: Washington 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 5.6 shows the annual selection of new energy efficiency as compared to the 10-year pro-rata share methodology.
For the 2020-2021 CPA, the two-year achievable potential is 63,450 MWh for Washington electric operations. The pro-rata share of the utility’s ten-year conservation potential is 70,977 MWh and therefore used in the calculation of the biennial target. Table 5.2
contains achievable conservation potential for 2020-2021 using the PRiSM methodology.
Also included is the energy savings expected from the 2020 and 2021 feeder upgrade projects. See Chapter 8 – Transmission and Distribution Planning for more information. The target also includes the efforts from Avista’s streetlight program, which should
achieve 272 MWh of savings between 2020 and 2021.
2021 2022 2030 2040
Industrial 4 8 50 84
Commercial 12 26 179 388
Residential 16 30 127 293
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Figure 5.6: Washington Annual Achievable Potential Energy Efficiency (Megawatt Hours)
Table 5.2: Biennial Conservation Target for Washington Energy Efficiency
2020-2021 Biennial Conservation Target (MWh)
EIA Target 71,481
Total Utility Conservation Goal 75,055
Utility Specific Conservation Goal 62,159
EIA Penalty Threshold 58,585
Table 5.3: Annual Achievable Potential Energy Efficiency (Megawatt Hours)

2020 Feeder Upgrades 269 0 269 2021 Feeder Upgrades 152 0 152

2020 LED Street Lighting 41 95 136
2021 LED Street Lighting 41 95 136

2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
PRiSM 31,769 63,450 95,953 126,401 161,602 198,365 235,673 273,843 313,230 354,887
10-Yr Pro-rata 35,489 70,977 106,466 141,955 177,443 212,932 248,421 283,909 319,398 354,887
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Energy Efficiency Related Financial Impacts
The Washington EIA requires utilities with over 25,000 customers 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 Washington 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 2020 conservation acquisition cost to electric customers is approximately $16.4
million. This amount grows to $32.9 million by 2021 and a total of $180.7 million over this 10-year period. Costs continue increasing after 2030 to over $344 million in 2040. Figure 5.7 shows the annual cost in millions of nominal dollars for the utility to acquire the projected electric achievable potential. 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 $8 million. This amount grows to $16 million by 2021 and a
total of $88.9 million over this 10-year period. Costs continue increasing after 2030 to
more than $169.7 million in 2040. Table 5.7 shows the annual cost in millions of nominal dollars for the utility to acquire the projected electric achievable potential. In total, the levelized price for Idaho’s savings is 3.4 cents per kWh. Figure 5.7: Cumulative Energy Efficiency Costs

4 The EIA defines cost effective as 10 percent higher than the cost a utility would otherwise spend on energy acquisition.
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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
the results are not detailed enough to form an actionable acquisition plan. Avista uses
both processes’ results to establish a budget for energy efficiency measures, help determine the size and skill sets necessary for future operations, and identify general target markets for energy efficiency programs. This section provides an overview of recent operations of the individual sectors, as well as energy efficiency business planning.

The CPA is useful 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 total resource cost or TRC (in Washington) and utility cost test or UCT (in Idaho) benefit-cost ratios, resulting in the lowest cost resources, brings the greatest amount of benefits to the overall portfolio.
• By identifying measures with great adoption barriers based on the economic versus achievable results by measure, staff can develop effective programs for measures with slow adoption or significant barriers.
• By improving the design of current program offerings, staff can review the measure level results by sector and compare the savings with the largest-saving measures currently offered. This analysis may lead to the addition or elimination of programs. Additional consideration for lost opportunities can lead to offering greater incentives on measures with higher benefits and lower incentives on measures
with lower benefits.
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 their sensitivity to more
detailed assumptions, feeds into program planning. Residential Sector Overview The Company’s residential portfolio uses several approaches to engage and encourage customers to consider energy efficiency improvements within their home. Prescriptive
rebate programs are the main component of the portfolio, but augment a variety of other interventions. These include upstream buy-down of low-cost measures (e.g. lighting and water saving measures) as well as white goods where this approach is more efficient than processing individual rebates. Other efforts include select distribution of low-cost lighting and weatherization materials, direct-install programs and a multi-faceted, multichannel
outreach and customer engagement. Residential customers received over $7.3 million in rebates to offset the cost of implementing these energy efficiency measures. All programs within the residential portfolio contributed over 29,766 MWh to the 2018 annual energy savings.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 90 of 259
In 2018, Avista moved to full implementation of its Multi-family Direct Install Program providing Avista customers with access to low-cost energy savings measures. The
program design allows for the direct installation of these measures at apartments and other multifamily living facilities. Avista added the program to its list of residential offerings to address the hard-to-reach segment, which has historically included tenants in rental agreements and multifamily housing situations. While providing low-cost energy saving measures is a primary driver of the program, it also gives the Company an opportunity to
provide energy efficiency education to customers and apartment managers. Low-Income Sector Overview The Company leverages the infrastructure of seven network Community Action Program (CAP) agencies and one tribal weatherization organization to deliver energy efficiency
programs for the Company’s low-income residential customers in Avista’s service territory. CAP agencies have resources to income qualify, prioritize and treat clients homes based upon a number of characteristics that are not available to Avista. In addition to the Company’s annual funding, the agencies have other monetary resources to leverage when treating a home with weatherization or other energy efficiency measures.
The agencies either have in‐house or contract crews to install many of the efficiency
measures of the program.
Avista’s general outreach is a “high touch” customer experience for our most 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 center activities, or
affordable housing developments. In 2018, Avista attended 116 events and reached well
over 11,000 customers in the Washington service territory along with 67 events and reaching 5,000 customers in the Idaho service territory. The low-income energy efficiency programs contributed 1,011 MWh of electricity savings
and 20,172 therms of natural gas savings in 2018.
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 homogenous.
In 2018, more than 2,100 prescriptive and site-specific nonresidential projects received
funding. Avista contributed over $10.2 million for energy efficiency upgrades in nonresidential applications. Non-residential programs realized over 57,000 MWh and 138,027 therms in annual first‐year energy savings.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 91 of 259
Conservation’s T&D Deferral Analysis
Cost-effective energy efficiency programs require a review of cost versus potential benefits. One benefit is the generation and delivery system investments avoided or deferred. Generation avoided investments are fairly 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 be reduced by energy efficiency due to the thermal limitations of the system. The 2017 IRP acknowledgement letter requested that 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 transmission and distribution systems. A forward-looking T&D deferral value could provide better alignment between the expected use of the Company’s 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. Avista uses a historical approach, also known as the current values approach. It considers the amount of current investment in both T&D from a revenue requirement reference
point, then divides by the peak load of the system, to estimate a $/kW-yr. value. This
method’s strength is its simplicity, lending itself to frequent updates, but it does not accurately portray the amount of deferred future T&D investment due to new conservation programs.
The impact of implementing a forward-looking T&D deferral value would attempt 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. A potential impact of a forward-looking methodology is that a component of the conservation avoided cost calculations could be incorrect or inaccurate.

The impact of implementing or continuing a historically-based methodology is the avoided cost included in the Company’s CPA does not address future known changes to the T&D system and those benefits would not be reflected in the avoided cost. However, the strength of this approach is that data related to its calculation uses published T&D values.

In an attempt to address the shortcoming of both methodologies, Avista chose to base its T&D deferral on its Cost of Service study with proforma values for plant resources. This adjustment attempts to provide a forward look for future T&D investments based on historic plant amounts. Avista utilizes the most recent Cost of Service study for its net
transmission and distribution values as provided in Dockets AVU-E-19-04 for Idaho and
UE-190334 for Washington. The strengths of this approach include values that are verifiable, published, and references in the Company’s general rate case along with estimates on the values of transmission and distribution assets for future periods.
Table 5.4 below illustrates the transmission and distribution values calculated for the
Company’s T&D deferred benefits for energy efficiency.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 92 of 259
Table 5.4: Transmission and Distribution Benefit
Transmission Net Book Value Distribution Net Book Vale
Washington 341,627,000 742,302,000
Idaho 178,117,000 352,752,000
Total 519,744,000 1,095,054,000
Revenue Requirement 519,826,223 1,175,906,417

Peak Load (MW) 1,693 1,693
Current $/kW 306.96 694.38
Levelized Cost 15.95 17.07
Total Levelized cost 33.01

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 93 of 259
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 unexpected emergency grid-operations situation. Traditional DR in the form of time-of-use rates, peak time rebates, direct load control programs or bi-lateral agreements
allow load reductions to specific enrolled customers during such periods until the load event is over or the customer has met their 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.
Avista’s experience with DR dates back at least to the 2001 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 again led Avista to request DR through media outlets for customers to conserve energy. We also initiated short-term agreements with large industrial customers to curtail loads. During the 2006 event, Avista estimates DR reduced loads by 50 MW. After the 2006 event, Avista implemented additional short-term bi-lateral agreements for DR with its
largest customers for use during grid emergencies. 2007-2009 Residential Demand Response Pilot The 2006 heat wave event led Avista to conduct a two-year residential load control pilot between 2007 and 2009 to study specific technologies and examine cost-effectiveness
and customer acceptance. The 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 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 feedback equipment. Information gained from the pilot is in the report filed with the Idaho Public Utilities Commission1.

1 https://puc.idaho.gov/fileroom/cases/elec/AVU/AVUE0704/company/20100303FINAL%20REPORT.pdf
Section Highlights
• Avista’s Demand Response experience dates back to at least 2001.
• response potential assessment for this IRP.
• This IRP studied 17 DR programs, up from four in the last plan.
• Demand Response receives a 40 percent peak credit against peak demand.
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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. 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 with 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 Project’s prime sponsor for use in the SGDP’s final project report and compilation with other SGDP initiatives2. Experiences from both DLC pilots show participating customer engagement is high; however, recruiting participants is challenging. Avista’s service territory has high natural
gas penetration level meaning many customers cannot benefit greatly from typical DLC space and water heat programs. Additionally, customers did not seem overly interested in the DLC programs as offered. BPA has 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 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 sponsors DR
potential assessment studies to identify the 20-year DR potential specific to Avista’s service territory for use in the resource selection process. The first study occurred for the 2015 IRP in response to a 2013 IRP Action Item, and subsequent studies performed for the 2017 and most current IRPs.
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 95 of 259
Demand Response Potential Assessment Study Avista retained AEG to study the potential of DR for all but the irrigation market sector in
Avista’s service territory for the 20-year planning horizon of 2021–20404. 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 is on resources assumed achievable during the planning horizon, recognizing known market dynamics may hinder 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, behavior and third party contract DR programs included in this study require AMI as an enabling technology. AMI deployment
is underway in Washington with completion slated for fall of 2020. AEG broadly assumed that Avista would follow with AMI metering in Idaho and used a three-year ramp rate for full deployment, finishing in 2025. As with the CPA study for Energy Efficiency, AEG looks at Avista’s customer accounts
and rates schedules to characterize the Market. This becomes the basis for customer segmentation to determine the number of eligible customers in each market segment for potential DR program participation. The DR study combined like customer segments in Washington and Idaho because Avista utilities operates across both states.
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
Rates programs.
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
4 Avista added an extra five years to study a 25-year time period.
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 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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large industrial curtailment and standby generation; these programs were not part of the AEG study.
Rates 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, variable peak, and real time pricing. Each option requires a new rate tariff. 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
Curtailment

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 through 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. 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 return,
participants receive fixed incentive payments. Customers receive payments even if
they never receive a load curtailment request. 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. Penalties are
a possible component of a firm curtailment program. Customers with 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.

In most cases, third parties 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 contract with a third party to deliver a fixed amount of capacity reduction 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. Thermal Energy Storage Thermal energy storage technologies draw electricity during low demand periods and
store it as heat with a thermal storage medium, such as bricks, water, or ice sealed inside
the unit. A variable speed fan can automatically circulate heat or cool throughout a room using the stored energy (heat or ice) rather than having to draw energy from the grid during peak times.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Battery Energy Storage Battery energy storage technologies draw electricity during low demand periods and store
it for use during peak times. This study assumes energy is stored using electrochemical processes. Behavioral This program is a voluntary reduction in response to digital behavioral messaging.
These programs typically occur in conjunction with Energy Efficiency behavior report programs. 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 in the context of integrating intermittent renewable resources such a solar and wind. A subset of participants from other DR programs such as DLC and firm curtailment customers 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. The DR study considered two types of TOU pricing options. With 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. 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 hot weather or other factors. System contingencies and emergencies are good candidates for variable peak pricing.
Real-Time Pricing Under real-time pricing, electricity rates vary by the hour, according to wholesale electricity market. Real-time pricing incentivizes customers to move a portion of their usage away from peak times to take advantage of lower electricity prices. The analysis
removed residential, small, and medium businesses because typically only large and extra-large customers participate in these types of programs according to AEGs findings. Studies show dynamic pricing programs, such as critical peak pricing, vary according to whether customers have enabling technology to automate their response. For large and extra-large general service customers, the enabling technology is
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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automated demand response implemented through energy management and control systems.
Large Industrial Curtailment The IRP includes a 25 MW large industrial curtailment program to take advantage of potential programs with one of Avista larger industrial customers. Program sizes are likely to be around 25 MW, but there is potential for up to 50 MW depending on the customers’
ability to be flexible. The concept of this program is to develop parameters for customer curtailment and compensate customers a fixed amount or an amount per curtailment. Standby Generation This program uses customer generators for a limited number of hours for peak
requirements, operating reserves, and potentially for voltage support on certain distribution feeders.
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, and economic environment are likely to influence
customer participation in DR programs.
Once initiated, DR options require a time-period to ramp up and reach a steady state because customers need time for education, outreach, and recruitment; in addition to the physical implementation and installation of any hardware, software, telemetry, or
other equipment. DR programs require careful consideration of the customer
engagement aspects of these options. DR programs included in the study have ramp rates generally in a three-year to five-year timeframe to reach their steady state. Demand Response Program Hierarchy
Independent assessments of DR programs considered each program as a standalone
offering. As such, 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 help provide a comparative assessment of individual DR programs and costs and are useful
for selection of DR programs in a program portfolio.
If Avista offers more than one program, then the potential for double counting exists. To address this possibility, a participation hierarchy defined the order in which customers take the programs for an integrated approach. The study computed savings and costs under this scenario.
Standalone DR programs are in the results section because of their use in modeling. For
detailed results using the integrated estimates, program participation rates and estimated peak reductions by program per market segment, please see Appendix A, AEG’s slide deck of Avista’s Demand Response Potential Assessment study.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Demand Response Program Results
Tables 6.2 through 6.5 show demand savings from individual DR programs for selected years of the analysis. These savings represent combined savings from DR options in Avista’s Idaho and Washington service territories.

Key findings:
• Third-party contracts have the highest savings potential;
• Opt-out TOU and variable peak pricing options have the second highest savings potential; and
• DLC for residential customers provides the third highest savings potential.
Table 6.2: Demand Response Achievable Potential (MW) – Winter DLC

Sector Option 2021 2022 2030 2040
Residential DLC Central AC - - - - DLC Water Heating 1.4 4.3 15.6 17.5 DLC Smart Appliances 0.3 0.8 2.8 3.1 DLC Smart Thermostats - Cooling - - - - DLC Smart Thermostats - Heating 1.3 3.9 14.5 16.8
DLC Electric Vehicle Charging 0.0 0.0 0.6 1.1
C&I DLC Central AC - - - - DLC Water Heating 0.1 0.4 1.6 1.7 DLC Smart Appliances 0.0 0.1 0.3 0.4 DLC Smart Thermostats - Cooling - - - - DLC Smart Thermostats - Heating 0.2 0.7 2.7 3.0
Third Party Contracts 3.4 9.5 23.0 23.2
Large Industrial Curtailment 25.0 25.0 25.0 25.0 Standby Generation 5.0 10.0 31.5 36.9
Total 36.7 54.7 117.6 128.7

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 101 of 259
Table 6.3: Demand Response Achievable Potential (MW) – Summer DLC

Sector Option 2021 2022 2030 2040
Residential DLC Central AC 0.5 1.4 5.4 6.2 DLC Water Heating 1.4 4.3 15.6 17.5 DLC Smart Appliances 0.3 0.8 2.8 3.1 DLC Smart Thermostats - Cooling 0.5 1.4 5.4 6.2 DLC Smart Thermostats - Heating - - - -
DLC Electric Vehicle Charging 0.0 0.0 0.6 1.1
C&I DLC Central AC 0.1 0.4 1.5 1.8 DLC Water Heating 0.1 0.4 1.6 1.7 DLC Smart Appliances 0.0 0.1 0.3 0.4 DLC Smart Thermostats - Cooling 0.1 0.4 1.5 1.8 DLC Smart Thermostats - Heating - - - -
Third Party Contracts 3.0 8.5 20.7 20.9
Large Industrial Curtailment 25.0 25.0 25.0 25.0
Standby Generation 5.0 10.0 31.5 36.9
Total 36.0 52.7 111.9 122.6
Table 6.4: Winter Demand Response Achievable Potential (MW)
Sector Option 2021 2022 2030 2040 Residential Time-of-Use Opt-in 0.6 1.9 6.5 6.9 Time-of-Use Opt-out 28.3 24.3 22.1 23.5 Variable Peak Pricing Rates 2.1 6.2 21.8 23.1 Ancillary Services 0.0 0.0 0.1 0.2 Battery Energy Storage 0.1 0.2 2.4 4.4
Behavioral 0.8 1.7 3.5 3.7 C&I Time-of-Use Opt-in 0.1 0.4 1.7 1.7 Time-of-Use Opt-out 8.2 9.3 9.4 9.4 Variable Peak Pricing Rates 0.3 1.5 6.2 6.4 Real Time Pricing 0.1 0.3 1.1 1.1 Ancillary Services 2.2 2.2 2.2 2.3 Thermal Energy Storage - - - -
Battery Energy Storage 0.0 0.0 0.4 0.8
Total 42.8 48.0 77.4 83.5

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 102 of 259
Table 6.5: Summer Demand Response Achievable Potential (MW)

Sector Option 2021 2022 2030 2040
Residential Time-of-Use Opt-in 0.6 1.8 6.4 6.8 Time-of-Use Opt-out 27.7 23.8 21.7 23.0 Variable Peak Pricing Rates 2.0 6.1 21.3 22.6 Ancillary Services 0.0 0.0 0.1 0.2 Battery Energy Storage 0.1 0.2 2.4 4.4
Behavioral 0.8 1.6 3.4 3.6
C&I Time-of-Use Opt-in 0.1 0.4 1.5 1.5 Time-of-Use Opt-out 7.2 8.3 8.4 8.4 Variable Peak Pricing Rates 0.3 1.3 5.6 5.7 Real Time Pricing 0.1 0.3 1.0 1.0 Ancillary Services 1.9 2.0 2.0 2.1 Thermal Energy Storage 0.0 0.2 0.8 0.8
Battery Energy Storage 0.0 0.0 0.4 0.8
Total 40.8 46.0 75.0 80.9
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 it contributes to meeting Avista reliability
criteria in peak load periods. This process is an Effective Load Carrying Capability (ELCC)
analysis. 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 whether or not there is a “snap back” effect. Loads without a snap back effect
shed load permanently, but loads exhibiting the snap back effect are higher later due to
the reduction from the DR program. Avista only had adequate time to conduct generic DR
programs assuming up to eight hours of load reduction. Our results were, resulting a 60
percent peak credit for an 8-hour DR load reduction. Avista concludes this is a result of
limited energy reduction when Avista needs of for winter energy in addition to winter peak
reductions.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 103 of 259
Demand Response Program Cost Estimates
The study includes cost estimates to achieve the savings results for both individual DR programs considered on a standalone basis and on an integrated basis. This takes into consideration any customer participation overlap that may occur if Avista
implements multiple programs simultaneously. The study modeled standalone costs
to be consistent with the savings modeling methodology. The key findings are pricing options have the lowest cost and DLC of heating loads with smart thermostats have the second lowest cost.
Table 6.6: 2021 Levelized Costs by DR Program (Standalone)
2021 Levelized Cost $/kW-yr $/kW-yr Winter Summer
Washington State House Bill 1444 Appliance Standards
The newly enacted legislation from Washington State House Bill 1444 (HB 1444) includes new design requirements for tanked style water heaters be manufactured with a CTA-2045 communication port that enables demand response. The Washington State Department of Commerce is currently in the rulemaking process to support HB
1444. Using a recent study published November 9, 2018 by the Bonneville Power Administration (BPA), AEG analyzed costs and impacts for a CTA-2045 water heater DR program. Impacts from the BPA study suggest a lower impact for CTA-2045 water
heaters than traditional water heater demand response programs included in the Seventh Power Plan. Even with increased participation the CTA-2045 water heaters
5 Avista is not including pricing for this program, as its economics is dependent on the negotiated price between the customer and Avista.
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would allow, it is not enough difference to overcome the reductions in impacts. As a result, the CTA-2045 water heater DR program was not included in Avista’s current
IRP modeling. Avista will revisit this DR program with guidance from the Department of Commerce’s final rulemaking in Washington State.

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7. Long-Term Position

This chapter describes the analytical framework used to develop Avista’s net resource position. It describes reserve margins held to meet peak loads, risk-planning metrics used to meet hydroelectric 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. It connects to several neighboring utility systems, but is only 5 percent of the total regional load. Annual peaks can occur either in the winter or in the summer; but Avista is winter peaking on a planning basis due to periods of extreme cold weather conditions. The winter
peak generally occurs in December or January, but may also happen in November or February. As described in Chapter 4 – Existing Supply Resources, Avista’s resource mix contains roughly equal amounts of hydroelectric and thermal generation. Hydroelectric resources meet most of Avista’s flexibility requirements for load and intermittent generation, though thermal generation is playing a larger role as load growth and
intermittent generation increase flexibility demands.
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 their 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-hydroelectric systems1,
but does not provide an estimate for energy limited system as such with Avista and the northwest due to hydro.
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; the first energy deficit is also in 2026.
• By 2021, clean resource generation equals 78 percent of retail sales.
• Avista exceeds renewable energy targets for WIndependence Act throughout this IRP.
• The regional resource adequacy situation is at risk due to planned coal plant retirements and load growth without the addition of new resources.
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Avista and the region’s hydroelectric system is energy constrained, so the 10 or 15 percent metrics from NERC do not adequately define our planning margin. Beyond
planning margins, as defined by NERC, a utility must maintain operating reserves to cover forced outages on the system. Avista includes operating reserves in addition to a planning margin. Per Western Electric Coordinating Council (WECC) requirements, Avista must maintain 3 percent of control area load and 3 percent of on-line control area generation plus Frequency Response Requirement (FRR) of 24 megawatts. Avista must also
maintain reserves to meet load following and regulation requirements of within-hour load and generation variability, this amount equals 16 MW at the peak hour. Avista’s planning margin in the 2017 IRP was 14 percent in the winter and 7 percent in the summer totaling a 22.6 percent planning margin (with reserves). 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 requirement of the study was to quantify by percentage the amount of additional generation above expected load to serve all load in 95 percent of the simulations, resulting in a 5 percent loss of load probability or less.
2020 IRP Resource Adequacy Assessment Early in the IRP process, Avista identified the same 14 percent planning margin requirement would be necessary for meeting future load in its second Technical Advisory Committee (TAC) meeting as in prior IRPs. This study assumes 250 MW is available from
the wholesale market,2 and Avista would need to add 240 MW of CTs (assumes two units). This analysis also assumes Colstrip Units 3 and 4 would be available to serve loads. With the passage of CETA, a new resource adequacy assessment was completed with
Avista’s Reliability Assessment model (ARAM) for 2030. This assessment included the following updated assumptions: the removal of Colstrip Units 3 and 4, an updated load forecast, and adjustments to resource maintenance schedules during the winter. This study and the prior studies are in Table 7.1 with monthly and annual LOLP results from the ARAM. The new study is resource adequate in a post CETA planning environment
(achieve the 5 percent LOLP) with 350 MW of capacity consisting of three new CTs. The 350 MW equates to a planning margin of 16 percent compared to 14 percent for the winter peak in the last IRP for the year 2030. Avista did not study other years for resource adequacy because of time and resource constraints.
As will be discussed in Chapter 11, a higher planning margin of 18 percent was ultimately required to achieve the 5 percent LOLP of the resources selected in the PRS. Ultimately, a combination of storage and intermittent resources requires higher planning margins than historical portfolios with constant fuel supplies. In the end, the planning margin target
2 The 250 MW of market availability was initially determined in the 2013 IRP. This study addresses the tradeoff of market exposure versus higher planning margins. In the end, this is a tradeoff between higher rates and higher reliability risk due to market reliance. Avista settled on 240 MW originally for market reliance as it was an acceptable level of risk as compared to added capacity cost.
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is rather a simplified measure of resource need; the quantity of resources needed to achieve 5 percent LOLP determines the actual need.
Table 7.1: 2020 Reliability Study Results
Additions w/ Additions w/o 350 MW CTs
Balancing Loads and Resources
The single-hour future load and resource projection is a simple method to identify any shortages. It highlights the potential of not serving loads in hours when the hydroelectric system (or future storage system) does not have enough energy available to operate at peak levels. In past IRPs, Avista used a three-day sustained peak analysis to illustrate
this concern. This method looked at the ability to serve 18 hours of peak loads over a
three-day period. While this method provides a good overview of the real problem of serving peak loads, the single hour was typically the larger shortfall. Avista addresses these requirements moving to the LOLP method for reliability planning but ultimately using the single and sustained peak analysis as supplementary insight. Figure 7.1 illustrates
the winter balance of loads and resources for the peak hour. The first significant winter
capacity deficit occurs in January 2026 when Avista assumes Colstrip exits the portfolio for IRP purposes. In October 2026, the deficit will increase when the Lancaster PPA expires.
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 7.2). Market purchases in the deep regional market should satisfy any weather-induced load variation or generation forced outage that
otherwise would be included in the planning margin as is the case in the higher winter
planning margin. The reliability analysis in Table 7.1 shows winter as the primary deficit period as resource additions to serve winter peaks meet smaller summer deficits as well.
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Figure 7.1: Winter One-Hour Capacity Load and Resources
Figure 7.2: Summer One-Hour Capacity Load and Resources

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Energy Planning For energy planning, resources must be adequate to meet customer requirements even
when loads are high for extended periods, or a sustained outage limits the contribution of a resource. 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 hydroelectric generation.
As with capacity planning, there are differences in regional opinions on the proper method for establishing energy-planning margins. 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. The IRP could target resource development to reach a 99 percent confidence level to deliver energy to its customers, and it would significantly decrease the frequency of its 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 of the 2017 IRP to cover a one-
in-one-hundred year event. Investments to support this high level of reliability would increase pressure on retail rates for a modest benefit. Avista plans to the 90th percentile for hydroelectric generation. Using this metric, there is a one-in-ten-year chance of needing to purchase energy from the market in any given month over the IRP timeframe.
Figure 7.3: Annual Average Energy Load and Resources

3 The critical water year represents the lowest historical generation level in the streamflow record.
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Washington State Renewable Portfolio Standard
Washington’s Energy Independence Act (EIA) requires utilities with more than 25,000 customers to source 9 percent of their energy from qualified renewables through 2019 and 15 percent by 2020. Utilities also must 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 for the EIA goals beginning in 2016. Since the last IRP, Avista acquired Rattlesnake Flats wind and Adam-Nielson Solar4 both qualify for EIA compliance.

Table 7.2 shows the forecast for RECs5 Avista needs to meet the EIA renewable requirement and the amount of qualifying resources already in Avista’s generation portfolio. Any utility in compliance with CETA is also compliant with the EIA. This table does not include the right to roll credits forward or backward by one year. Avista uses this
banking flexibility to manage variation in production. Table 7.2: Washington State EIA Compliance Position Prior to REC Banking (aMW)
2018 2020 2025 2030 2035
649.6 660.1 669.2 680.8 689.2
Net Renewable Goal
Other Available REC's
Net Renewable Position (before rollover RECs) 49.3 47.7 51.9 50.2 -49.7

4 Adam-Neilson will qualify after the Solar Select program ends.
5 These RECs are qualifying RECs within Avista system. For state compliance purposes the Company my transfer RECs between state’s allocation shares at market prices. Further, Avista may sell excess RECs to lower customer rates.
6 Rattlesnake Flat may also qualify for the apprentice credits, creating a 20 percent adder to the REC amount for compliance.
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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. Avista did not model all alternative
compliance options for this plan due to the fact rules are not yet in place to define all
potential programs qualifying for this designation with the exception of unbundled RECs. For this IRP, Avista assumes REC’s from Idaho’s share of the hydroelectric system is limited to the 20 percent portion of its compliance, and its contribution declines each year through 2045. Although, Idaho’s hydro share may qualify for meeting all targets in
Washington subject to rulemaking and Idaho’s interest in selling the renewable attributes
associated with the generation. Between now and 2030, Avista is expected to ramp into the 80 percent goal, although the rate of the ramp is to be proposed by the utility. Avista set the target of 75 percent clean by 2025 and 80 percent by 2030. Figure 7.4 shows this target as the blue line. After 2030, the blue line increases every four years until it is close
to meeting 100 percent of retail sales.
The target never reaches the retail sales (black line) due to a provision in CETA subtracting PURPA purchases from retail sales. The figure shows Avista’s current qualifying resources in green. These include Washington’s entire allocated share of the
hydroelectric system (both owned and PPAs) and the renewable resources shown in
Table 7.2. Idaho customers also have a claim to their share of renewable attributes, but Avista assumes like in the EIA the reassigning of these attributes to Washington customers with compensation to Idaho customers for the transfer. Given these estimates, Avista needs to acquire additional renewable resources for CETA beginning in 2026 for
Washington customers as the shortfall reaches nearly seven average megawatts. The
Company will be short of the 80 percent non-emitting requirement by 54 aMW in 2030 and 350 aMW short of the 100 percent 2045 goal. Avista plans to comply with the 20 percent component of the law by transferring RECs from Idaho to Washington in a similar manner as the EIA compliance. Avista acknowledges final rule making regarding
complying with the CETA law may alter Avista needed either higher or lower than set in
this plan. Avista will continue to work with the 2020 WUTC and other partings in the rulemaking process to finalize the rules for preparation of the 2021 IRP.
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Figure 7.4: Washington State CETA Compliance
Avista’s 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. From
a resource planning perspective, the 2027 goal entails ownership or control of renewable
resources or RECs equal to retail sales by 2027 and phase out all carbon producing generation by 2045. Each of these goals must consider cost implications in relation to the technical feasibility. This section discusses the amount of energy needed to meet the corporate goals. By 2021, Avista will have clean generation over the course of a year to
meet 78 percent of retail sales. By 2030, Avista would need to acquire an additional 340
aMW of clean energy or RECs to achieve its 2027 goal; by 2045, the deficit grows to nearly 560 aMW. In addition to the energy need in 2045, the Company will need to add 636 MW to meet the current resource gap and also replace the 590 MW the existing thermal resources provide on a winter peak day for 1,226 MW total. This potential new
capacity will need to be able to operate in cold winters and meet Avista’s five percent
LOLP reliability threshold.
Washington Existing Qualifying Resources
Washington Net Requirement
Washington Retail Sales
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Figure 7.5: Avista Clean Energy Goal
Regional Resource Adequacy
Avista relies on 250 MW of market power in the reliability study. If Avista chose not to rely on market power, its planning margins would be over 30 percent. Avista is not an electrical island, and other entities should be able to assist Avista when load peaks. Collectively, utilities should plan as a system and optimize resources to meet the region’s needs. This
may be an optimistic goal, as some utilities do not always make their excess capacity
available. 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 resource adequacy study by the 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 20247
on October 31, 2019 highlighting potential resource adequacy risks to the system. The
NPCC estimates the regional 2021 LOLP to be 7.5 percent exceeding the region’s threshold for resource adequacy due to announced coal plant retirements. The likelihood of lost load increases to 8.2 percent by 2024 with a regional 800 MW capacity shortage. When additional resources retire in 2026, the LOLP increases to 17 percent. Using the
results from this study equates to a regional planning margin of 13.4 percent8.
7 https://www.nwcouncil.org/sites/default/files/2024%20RA%20Assessment%20Final-2019-10-31.pdf.
8 This assumes the BPA’s White Book’s average peak capacity for regional hydro generation and 2,500 MW of imports.
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The regional analysis also conducts sensitivities regarding the level of load from economic growth and level of imports from other regions. Table 7.3 shows the range in
analysis provided by the NPCC for the LOLP in the first three rows and the megawatts required of needed 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 is able to acquire winter capacity from other regions.
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 lost load occurs in the winter months, primarily January; the study found 27 percent of events were in this month, followed by 19 percent in December. The summer had a collective LOLP of 26 percent.
Energy and Environmental Economics (E3) Study
Avista participated in a regional study to understand the resource adequacy needs with different potential clean energy legislation options. This study is included as Appendix F. The first year reviewed in the study was 2018 to test the model with the existing system. The study also reviews 2030 and 2050 under multiple resource acquisition strategies.
The footprint of this study includes 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 sufficient capacity to meet a goal of less than 2.4 outage hours per year (6.5 hours)9. E3 estimates 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 resource retirements and load growth. Avista’s Market Study
Avista details its market price forecast in Chapter 10, as part of this forecast is a forecast
of the needs of the region to maintain resource adequacy. This forecast estimates the generation need using an estimate of system load and resources. It does not consider individual resource needs or ability to transfer power within the region. This study shows a need for 840 MW of new natural gas-fired resource capacity to maintain resource
adequacy in 2025. The region requires an additional 700 MW between 2026 and 2045.
In addition to the natural gas-fired capacity, the region requires 250 MW of storage by
9 As discussed on page 36 of Appendix F.
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2025 and 2,000 MW by 2045. These additions are required along with the capacity benefits included within the wind and solar required to meet state clean energy goals.
Regional Resource Adequacy Conclusions Avista’s review of regional studies and its own study show the region is at risk for not meeting customer loads today. Avista is in a strong position in the current market shortfall by exceeding its planning margin requirements through 2025. Although after 2025, Avista
and many other utilities must acquire new dependable capacity resources to ensure customers have adequate power to sustain both extended cold winter and hot summer periods.

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8. Transmission & Distribution Planning

This chapter introduces the Avista Transmission and Distribution systems and provides a brief description of how Avista studies these systems and recommends projects to keep
the systems functioning reliably. Avista’s Transmission System is only one part of the
networked Western Interconnection, so a discussion of regulations and regional planning is also provided. This chapter includes a brief summary of 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 now playing a role in the IRP and the rights of Avista’s merchant
transmissions system.
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 a transmission and distribution system plan annually.
• Transmission Avista system.
• Distribution planning evaluates potential storage opportunities that may allow
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230 kV Transmission System The backbone of the Avista Transmission System functions 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 its 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 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 operating and planning among its membership. WECC is the largest
geographic territory of the regional entities with delegated authority from the NERC and the FERC. It covers all or parts of 14 Western states, the provinces of Alberta and British
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Columbia, and the northern section of Baja, Mexico.1 See Figure 8.3 for the map of WECC.
RC West 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 operations in support of
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 a number of committees, including its Operating Committee, the Reserve Sharing Group Committee, the Pacific Northwest Coordination Agreement (PNCA) Coordinating Group, and the Transmission Planning Committee (TPC). ColumbiaGrid
ColumbiaGrid formed on March 31, 2006. Its membership includes Avista, BPA, Chelan County PUD, Grant County PUD, Puget Sound Energy, Seattle City Light, Snohomish County PUD, and Tacoma Power. ColumbiaGrid 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 890 and 1000,
ColumbiaGrid provides an open and transparent process to develop sub-regional transmission plans, assess transmission alternatives (including non-wires alternatives),
1 https://www.wecc.biz/Pages/About.aspx
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and provides a decision-making forum and cost-allocation methodology for new transmission projects. During 2020, Avista will transition its regional transmission
planning from ColumbiaGrid to the newly formed NorthernGrid. NorthernGrid is a new regional planning organization created by combining members of ColumbiaGrid and the Northern Tier Transmission Group. Northern Tier Transmission Group
The Northern Tier Transmission Group (NTTG) formed on August 10, 2007. NTTG members include Deseret Power Electric Cooperative, Idaho Power, Northwestern Energy, PacifiCorp, Portland General Electric, and Utah Associated Municipal Power Systems. These members rely upon the NTTG committee structure to meet FERC’s coordinated transmission planning requirements. Avista’s transmission network has a
number of strong interconnections with three of the six NTTG member systems. Due to the geographical and electrical positions of Avista’s transmission network related to NTTG members, Avista participates in the NTTG planning process to foster collaborative relationships with our interconnected utilities. During 2020, Avista will transition its participation in NTTG to the newly formed NorthernGrid.
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 ColumbiaGrid transmission planning process (will transition to the new
NorthernGrid process in 2020) – as provided in the ColumbiaGrid Planning and Expansion Functional Agreement (PEFA) and the ColumbiaGrid Order 1000 Functional Agreement,
• 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 located in the Transmission Planning folder on Avista’s OASIS. The Avista System
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Planning Assessment is posted on OASIS. Avista’s most recent transmission planning document highlights several areas for additional work including:

• Big Bend- Transmission system performance will significantly improve upon completion of the Benton – Othello Switching Station 115 kV Transmission Line Rebuild project. Other area improvements include the Saddle Mountain 230 kV
Station project, the addition of communication aided protection schemes and other reconductor projects.
• Coeur d’Alene- A comprehensive long term plan is needed to mitigate both
transmission and distribution capacity related performance issues in the Coeur d’Alene area. 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 has improved transmission system
performance. The addition and expansion of distribution substations and a
reinforced 115 kV transmission system are needed in the near term planning horizon.
• Lewiston/Clarkston- Load growth in the Lewiston/Clarkson area has 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.
• Palouse- Completion of the Moscow 230 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.

• Spokane- Several performance issues exist with the present state of the transmission system in the Spokane area and worsen with additional load growth.
The staged construction of new 230 kV facilities at the Garden Springs 230 kV and
Ninth and Central 230 kV Stations to reinforce the area will be required. Dependency on Beacon Station leaves the system susceptible to performance issues for outages related to 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, we anticipate that all identified generation integration transmission costs will not be directly
attributable to a new interconnected generator.

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Large Generation Interconnection Requests Third-party generation companies may request transmission studies to understand the
cost and timelines for integrating potential new generation projects. These requests follow a strict FERC process, including three study steps 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 Table 8.1: 2020 IRP Generation Study Transmission Costs Station Request (MW) POI Voltage Cost Estimate ($ million)3

2 https://www.oasis.oati.com/woa/docs/AVAT/AVATdocs/GIP_Queue-V100_(public).pdf
3 Cost estimates are in 2019 dollars and use engineering judgment with a 50 percent margin for error. 4 This area of the system as several projects in the transmission request process, in total these projects exceed the local area’s ability to integrate new resources and currently being studied.
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Table 8.2: Third-Party Large Generation Interconnection Requests
Project Size (MW) Type Interconnection Location Proposed Date

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Distribution Planning
Avista continually evaluates its distribution system. The distribution system consists of approximately 347 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 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 includes whether or not 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 then the best course of action is
budgeted. The primary role of electric distribution planning is to identify system capacity and service reliability constraints, and subsequently identify the best and lowest life-cycle cost
solution. Traditionally this solution has centered on infrastructure upgrades such as poles,
wire, and cable. New technologies are emerging that may impact system analysis, including storage, photovoltaic (solar), and demand response. As these alternatives mature and evolve they are likely to play a role in our investment portfolio either as primary solutions or capital deferment solutions. Avista has deployed several pilot projects with
the intent of determining how best to meet customer needs and maintain a high degree
of reliability now and in the future. To properly evaluate each feeder for new technologies, load data and system data is required. Quality load data is not available for all Avista feeders beyond monthly data logs
recording peak load and energy. Without detailed load data, evaluating new technologies
is limited to portions of the system with the available data. Detailed data is required to validate whether new technologies solve current system constraint or just defers the constraint to a different time. Avista is currently installing automated meters for customers in Washington. When complete, the new meters will be able to collect additional data to
improve the distribution planning process.
Currently, 195 of 347 feeders have three-phase SCADA (Supervisory Control and Data Acquisition) data available. Avista adds SCADA capability to additional feeders as resource and budgeting allow within our substation work schedule. As more demands
beyond traditional capacity constraints and level of service requirements are placed on
the grid, an increased amount of data is required to analyze and enhance the electric distribution system. As Avista implements its smart meters, much of the data can be compiled using the customer meter data alleviating the immediate need for SCADA related data collection.

New load forecasting techniques such as spatial load forecasting will be required. This new forecasting method uses GIS based information associated with feeder location and can help forecast specific feeder load growth taking into account zoning, demographics, land availability, and specific parcel information. With additional investment in both
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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 other investments. This is dependent on the new technology 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 can help meet overall power supply peak load needs, but it may also improve local reliability by providing voltage support and deferring capital investment on the distribution feeder or at the distribution substation.
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 the peaks occur, whether they are near capacity or not, and how
fast loads are growing in the area. It is not practical to have an estimate for each feeder in an IRP, but it is prudent to have a representative estimate to include in the resource selection analysis. For this IRP, Avista attempted a proof in concept of analyzing distribution feeder upgrades
in the overall IRP analysis. The trial analysis includes distribution needs in the optimization of resources. Specifically, when solving for new resources to meet electric load, the optimization includes a requirement to solve a distribution feeder requirement. For this analysis Avista used the Huetter feeder in North Idaho. The model was given three options to solve the future shortfall in capacity. Two of the options were wire plans.
The first is to add new regulators then add a new transformer later, the second is to add the new transformer now and not add regulators. Regulators allow for the deferral of a new transformer by three years. The regulators cost approximately $80,000, while a new transformer can cost up to $3 million. The third alternative is a non-wire alternative, adding the regulators then adding batteries with eight hours of storage capability rather than the
new transformer. The storage resource could then alleviate a distribution requirement while also assisting the power system. Conducting this analysis in the PRiSM model includes both the benefits of the distribution system and the power system. The model found the first option of installing the regulators now, then later installing a new transformer was the preferred option.
Grid Modernization In 2008, an Avista system efficiencies team of operational, engineering, and planning staff developed a plan to evaluate potential energy savings from transmission and distribution system upgrades. The first phase summarized potential energy savings from distribution
feeder upgrades. The second phase, beginning in summer 2009, combined transmission system topologies with right sizing distribution feeders to reduce system losses, improve system reliability, and meet future load growth. The system efficiencies team evaluated
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several programs to improve urban and rural distribution feeders. The programs consisted of the following system enhancements:

• Conductor losses;
• Distribution transformers;
• Secondary districts; and
• Volt-ampere reactive compensation.
The analysis combined energy losses, capital investments, and reductions in O&M costs resulting from the individual efficiency programs under consideration on a per feeder basis. This approach provided a means to rank and compare the energy savings and net resource costs for each feeder. Building on the 2009 effort, a 2013 study assessed benefits of distribution feeder automation for increased efficiency and operability. The
Grid Modernization Program (GMP) combines work from system performance studies and provides Avista’s customers with refreshed system feeders with new automation capabilities across the Company’s distribution system. Table 8.3 shows the feeders currently planned for rebuild and their associated energy savings. The total energy savings from both re-conductor and transformer efficiencies for all completed feeders is
approximately 1,206 MWh annually. The GMP charter ensures a consistent approach to how Avista addresses each project. This program integrates work performed under various Avista operational initiatives, including the Wood Pole Management Program, the Transformer Change-Out Program,
the Vegetation Management Program, and the Feeder Automation Program. The Distribution GMP includes replacing undersized and deteriorating conductors, and replacing failed and end-of-life infrastructure materials including wood poles, cross arms, fuses, and insulators. It addresses inaccessible pole alignment, right-of-way, under-grounding, and clear-zone compliance issues for each feeder section, as well as regular
maintenance work including leaning poles, guy anchors, unauthorized attachments, and joint-use management. This systematic overview enables Avista to cost-effectively deliver a modernized and robust electric distribution system that is more efficient, easier to maintain, and more reliable for our customers.
Table 8.3: Planned Feeder Rebuilds
Complete Savings (MWh)
BEA12F2 Spokane, WA 2020 269
ROS12F5 Spokane, WA 2021 152
SIP12F4 Spokane Valley, WA 2022 283
M15514 Moscow, ID 2023 245
MIS431 Kellogg, ID 2023 257

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Merchant Transmission Rights
Avista transmission rights are in two parts. The first is Avista’s owned transmission. This transmission is used by Avista’s merchant department to serve Avista customers or is available to other utilities or power producers. The merchant department dispatches and
controls the power generation for Avista. FERC separates utility functions between
merchant and transmission to allow for fair access to the Avista transmission system. Avista also purchases transmission from other utilities to serve customers. Specifically this is transmission procured on the 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 rights of the Merchant’s transmission. Avista also must show a load
serving need to reserve transmission on the Avista owned transmission system to ensure equitable access to the transmission capacity. Appendix E shows the projected need and future use of the Avista transmission system.
Table 8.4: Merchant Transmission Rights
BPA Lancaster to John Day 100 6/30/2026
BPA Coyote Springs 2 to Hatwai 97 8/1/2026
BPA Coyote Springs 2 to Benton 50 8/1/2026
BPA Garrison to Hatwai 196 8/1/2026
BPA Coyote Springs 2 to Vantage 125 10/31/2022
BPA Townsend to Garrison 210 9/30/2027
PGE John Day to COB 100 12/31/2023
Northern Lights Dover to Sagle As needed n/a Kootenai Electric Rockford to Worley As needed 12/31/2028

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9. Supply-Side Resource Options

Avista evaluates several generation supply-side resource options to meet future resource deficits. The resource categories evaluated for this IRP include upgrading existing resources, building and owning new generation facilities, and contracting with other energy companies. This section describes resource options Avista considers in the 2020
IRP. The options are mostly generic, as actual resources are typically acquired through competitive processes. This process may yield resources that differ in size, cost, and operating characteristics due to siting, engineering, or financial requirements.
Assumptions
Avista models only commercially available resources with well-known costs and generation profiles priced as if Avista developed and owned the generation or acquires
generation from Independent Power Producers (IPPs) with a Purchase Power Agreement
(PPA). Resources modelled as PPAs include pumped storage, wind, solar, geothermal, and nuclear resources. Avista modeled these resource types as PPAs since IPPs are able to financially capture tax benefits for these resources earlier, which reduces the cost to customers. Other resource options assume utility ownership include natural gas-fired
combined cycle combustion turbines (CCCT), simple cycle combustion turbines (SCCT),
natural gas-fired reciprocating engines, energy storage, biomass, hydroelectric upgrades, hydroelectric contracts, and thermal unit upgrades. Upgrades to coal-fired units are not included or considered in the IRP analysis. Modeling resources as PPA 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 PRS analysis, but we discuss them as potential resource options since they may appear in a request for a future resource acquisition.
It is difficult to accurately model potential contractual arrangements with other energy
companies as an option in the plan, but such arrangements may offer a lower customer cost when a competitive acquisition process is completed. Avista plans to use a competitive RFP process for all resource acquisition where possible to ensure the lowest cost resource is acquired for our customers; although other acquisition process may yield
Section Highlights
• Solar, wind, and other renewable resource options are modeled as Purchase Power Agreements (PPA) instead of utility ownership.
• Upgrades to Avista’s hydroelectric, natural gas and biomass included as resource options.
• Future competitive acquisition processes might identify different technologies
available to Avista.
• 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.
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better pricing on a case-by--case basis – especially for existing resources for shorter time periods. When evaluating upgrades to existing facilities Avista uses the IRP, RFPs, and
market intelligence to determine and validate its assumptions to pursue the upgrade. Upgrades typically require competitive bidding processes for contractors and equipment when available. The costs of each resource option do not include the transmission expenses described in
Chapter 8 – Transmission & Distribution Planning, all cost are considered at the bus bar. Avista excludes these costs in this chapter to allow for cost comparison as resource costs at specific locations depend on the location chosen. When Avista evaluates the resources for selection in the IRP, it includes these costs. All costs are levelized by discounting nominal cash flows by a 6.68 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 characteristic assumptions for generic resources and how PPA pricing is calculated is available in Appendix F.
Avista relies on several sources including the NPCC, press releases, regulatory filings, internal analysis, developer estimates, and Avista’s experience with certain technologies for its generic resource assumptions. For this IRP, Avista also engaged Black and Veatch to perform a reasonability test of our resource assumptions. This report is available Appendix G.
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 reality, 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 very 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 turbine is available 92 to 95 percent
of the time when taking into account maintenance and forced outage rate. Avista divides the cost by the amount of megawatt hours the machine is capable of producing. 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.
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.
1 Storage technologies use a $ per kWh rather than $ per kW because the resource is both energy and capacity limited. 2 Peak credit is the amount of capacity a resource contributes at the time of system one-hour peak load.
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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 emission of carbon dioxide. 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 250 MW and 350 MW each depending on configuration and location. A two-on-one (2x1) CCCT plant configuration is possible with two turbines and one HRSG, generating up to 650 MW. Avista would need to share a 2x1 plant to take advantage of the modest economies of scale and efficiency of a 2x1 plant configuration due to its large size relative
to Avista’s needs. 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 for a hybrid system utilizing the benefits of combined evaporative and convective technologies. This IRP models five types of CCCT plants, ranging in sizes 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 location and at other locations. It is also possible Avista could acquire an existing combined cycle
resource from one of the many 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 previously secured a site with these potential connection points in the event it needs to add additional capacity from either a CCCT or another technology.
Combined cycle technology efficiency has improved since Avista’s current generating fleet entered service with higher heating value heat rates as low as 6,500 Btu/kWh for a larger facility and 6,600 for smaller configurations. Duct burners can add additional capacity with heat rates in the 7,200 to 8,400 btu/kWh range.

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 has carbon dioxide mitigation fees for new plants.
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The anticipated capital costs for the two modeled CCCTs, located in Idaho on Avista’s transmission system with AFUDC on a greenfield site range between $905 to $1,529 per
kW in 2020 dollars. A likely configuration of the modern technology is $1,052 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 resource 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 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 and their simpler design relative to CCCTs allow them to start and ramp quickly, providing regulation services and reserves for load following and variable resources integration.
Natural gas-fired peakers have similar benefits and costs as CCCTs. This IRP models frame, hybrid-intercooled, reciprocating engines, and aero-derivative peaking resource options. The peaking technologies have different load following abilities, costs, generating capabilities, and energy-conversion efficiencies. Table 9.2 shows cost
and operational characteristics based on internal engineering estimates and reviewed by Black & Veatch. All peaking plants assume 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 reliability issue with FERC and 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, and liquefied natural gas storage.

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Table 9.1: 2020 Natural Gas-Fired Plant Levelized Costs
$/MWh (Capability) $/MWh Capacity
Advanced Large Frame CT 48 118 35 220
Advanced Small Frame CT 62 163 43 186
Frame/Aero Hybrid CT 54 159 35 106
Large Reciprocating Engine Facility 52 165 33 189
Small Reciprocating Engine Facility 54 183 33 47
Modern Small Frame CT 58 172 39 49
Aero CT 59 195 36 45
1x1 Advanced CCCT 46 151 29 362
1x1 Modern CCCT 48 171 27 306
Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics
Cost with AFUDC ($2020/kW)
O&M ($2020/kW- yr)
Rate (Btu/ kWh)
O&M ($/MWh) Project Size (MW)
Cost (Mil$-2020)
Advanced Large Frame CT 679 2.08 9,148 2.08 245 166
CT 969 5.20 11,049 3.12 84 81
1,031 3.12 8,856 3.12 92 95
Engine Facility 1,055 7.28 8,296 3.12 184 194
1,162 13.53 7,891 4.16 91 106
1,088 4.16 9,931 2.60 48 52
1,239 6.24 10,335 2.60 45 56
1,052 14.57 6,668 3.12 413 434
979 17.69 6,586 3.90 308 302

Wind Generation
Wind resources benefit from having no direct emissions or fuel costs, but they are not typically dispatchable to meet load. Avista is modeling four wind location options in the plan: Montana, Eastern Washington, Columbia Basin, and offshore. Configurations of facilities are changing given transmission limitations in the region and the benefits of tax
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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 integrate. When
the wind facilities generate additional MWh above the physical transmission limitations4, the generators typically feather or could store energy using on site energy storage. At this time, Avista is not modelling wind with onsite storage or wind facilities with greater output capabilities then can be integrated on the transmission system.
Onshore winds capital costs in 2020, including AFUDC, are $1,568 per kW for Washington on-system projects, off-system projects including Oregon and Montana are $1,458 per kW, and off-shore wind is $3,569 per kW. The annual fixed O&M costs of $36.40 per kW-year for on-shore wind and $93.60 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 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 40 to 50 percent range in Montana and offshore locations. This plan assumes Northwest wind has a 37 percent average capacity factor. A statistical method, based on regional wind studies, derives a range of annual capacity factors depending on the wind regime in each year (see stochastic modeling assumptions for details).
This IRP also estimates potential costs for offshore wind. Offshore wind has the potential for higher capacity factors (50 percent), but 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.
As discussed above, levelized costs change substantially due to 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 location. These price estimates assume the facility is acquired using a 20-year PPA with a flat pricing structure, but also includes the intermittent generation integration charge for the first 100
MW to Avista’s system and includes costs associated with passing the cost of the PPA to customers, excise taxes, commission fees, and uncollectables. These costs do not include the transmission costs for either capital investment or wheeling purchases. If a PPA is selected in Avista’s resource strategy (Chapter 11), the model assumes the PPA will extend through the 25-year time period.

4 In the event transmission is limited due to contractual reasons; an additional option is to buy non-firm transmission to move the power.
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Table 9.3: Levelized Wind Prices ($/MWh)
Year On-System Wind Off-System Wind Montana Wind Off-Shore Wind
Photovoltaic Solar
Photovoltaic (PV) solar generation technology costs fell substantially over the last several
years partly due to low-cost imports and from demand driven by renewable portfolio standards. Solar systems are now built with more generating capacity than the transmission interconnect limit to take advantage of increased energy produced throughout the year when only limited hours of the year occur when full production is
produced. Some systems, also have storage connected to the system to help with
integration of intermittent production, store excess energy to avoid curtailment, or shift 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 as long as the stored energy is from solar production. 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. It is possible future solar incentives will be similar to the Production Tax Credit rather than the ITC.
Avista models four potential solar systems, the first is an on-system solar facility in 25 MW (AC) increments, but modelled as a facility with at least 100 MW to take advantages of economies of scale. It is Avista’s understanding the solar costs can change significantly depending on size; to address this issue, a smaller 5 MW (AC) on-system is also included. The third solar option includes a facility to be wheeled to Avista in higher solar production
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areas such as southern Idaho or Oregon. Although if and when Avista attempts to acquire solar energy any location is acceptable to participate in the RFP, but transmission
charges and availability will be used to determine if the project(s) to move forward. Solar capital costs have been rapidly declining, even with increasing tariffs costs. Technology 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 $1,156 per kW
(AC) for a single axis tracking system; by 2030, these costs are expected to rise to $1,255 per kW and $1,455 per kW by 2040. 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 $1,399 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 costs vary, Avista assumes $8 per kW-year for larger systems and $10 per kW-year for smaller systems. Table 9.4 shows the levelized prices for 20-year flat PPA with additional costs to integrate the first 100 MW of intermittent generation, excise taxes, commission fees, and
uncollectables. These costs do not include the transmission costs either for investment or wheeling purchases. The prices also assume current phase-out of federal tax credits by 2024. Table 9.4: Levelized Solar Prices

Year On-system Southern NW On-system- small facility
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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, helps manage intermittent generation, uses common equipment, increases peak reliability, and prevents energy oversupply. Avista must study each potential benefit to see its value and the amount of storage duration 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 falling and will likely continue to fall. Avista estimates the additional cost for more hours of storage in Table 9.5 for solar PPAs. Avista modeled
one, two, and four-hour durations; although, 15 to 30 minutes will be considered if the technology is limited to assist with intermittent generation rather than reliability. Avista’s experience with solar generation from its 19.2 MW Adams-Neilson PPA show significant energy variation due to cloud cover. Avista will identify in future IRPs the cost of this variability on different size projects in the event of future acquisition. For this IRP, Avista
considers savings for integration and resource adequacy but due to the complexity and range of potential configurations, requires the utility to continue this analysis as Avista’s system changes with less thermal resources and more intermittent resources. In addition, Avista’s modeling of solar plus storage allows the storage device to use grid power as it may after six years. Table 9.5: Storage Cost w/ Solar System ($/kW-month)
Year One-Hour Two-Hour Four-Hour
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Stand Alone Energy Storage Energy storage resources are gaining significant traction as a resource of choice in the
western U.S., although energy storage does not create energy (it shifts it from one period to another in exchange for a portion of the energy stored). Avista is modelling several energy storage options including pumped hydro storage hydro, 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 pricing for existing technologies, new technologies are entering the storage space. For example, iron flow batteries became a commercial technology while producing this IRP. The rapid change in pricing and new available technologies justifies the need for frequent IRP analysis on an every other year basis.
Another challenge with storage is in the pumped hydro technology where costs and storage duration can be substantially different depending on the geography of the 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. Avista considers this as a benefit here, but discusses it further in Chapter 8- Transmission and Distribution Planning 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. 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. Pumped Hydro The most prolific energy storage technology currently 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 up to a higher reservoir and released during higher price or load periods. Over time this technology may help with meeting system integration issues from intermittent generation resources. Currently only one of these projects exist in the northwest and several more are in various stages of the permitting process. An advantage with pumped hydro is the technology has
long service lives and is technology Avista is familiar with as a hydro generating utility. The greatest disadvantages are large capital costs and long-permitting cycles. The technology has good round trip efficiency rates (Avista assumes 81 percent). 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 hours, 12 hours, 16 hours, 24 hours, 40 hours, and 80 hours. These durations are the amount of hours the project can run at full capacity. Modeling different duration
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times are required because in an energy-limited system, Avista requires resources with enough energy to provide reliable power over an extended period in addition to single
hour peaks. This study uses the ELCC analysis discussed later in the chapter. Avista bases its pricing for pumped hydro using a PPA financing methodology with fixed and variable payments. The price estimate for pumped hydro is a 2020 capital cost of $2,936 per kW with $15.60 per kW of Fixed O&M per year. This results in a 2020 PPA price of $22.28 per kW-month and $5.00 per MWh of generation. These prices are generic in
nature, and certain projects in the northwest have lower estimates. Avista choose to also model a lower price point of $12.50 per kW-month in the event a project has lower costs due to favorable siting or permitting. With these two price points considered, Avista believes these two price points provide enough range in pricing. A future RFP will determine pumped hydro’s actual pricing and availability. Avista is conducting internal
studies of the availability of pumped storage in or around its service territory. These studies may provide additional resource options in future IRPs or RFP processes. Lithium-ion As discussed before, lithium-ion technology is one of the fasted 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 as a PPA format as well with two 10-year cycles for a 20-year life. Fixed O&M costs are included in
pricing for replacements cells to maintain the storages energy conversion efficiency. 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 drives prices lower and permits utility scale projects.
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Figure 9.1: Lithium-ion Capital Cost Forecast
Avista models six conceptual stand-alone configurations for lithium-ion batteries. Two small-scale sizes (3 MW) with four and eight hour durations for modeling the potential for
use on the distribution system and four larger systems (25 MW) including four and eight
hour durations, but also theoretical 16 and 40 hour configurations. Pricing for this technology was set in the winter 2018/2019 using publically available pricing and forecasts, as well as review by Black & Veatch. 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 $1,188 per kW or $297 per kWh for 2021. Fixed O&M
costs are also expected to decline; Avista assumes for the 4-hour technology an annual cost of $44.30 per kW year in 2020 and by 2030 fall to $30.70 per kW-year. Storage technology is often displayed in many methods to illustrate the cost because it is
not a traditional capacity resource. Table 9.6 below shows levelized cost per kWh for each
configuration. This calculation factor levelizes the cost for the capital, O&M, and regulatory fees over 20 years divided by the capacity’s duration. These costs do not consider the variable costs, such as energy purchases.

Distribution Scale 4hr
Distribution Scale 8hr
Utility Scale 4 hr
Utility Scale 8 hr
Utility Scale 16 hr
Utility Scale 40 hr
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Table 9.6: Lithium-ion Levelized Cost $/kWh
Year Distribution Scale 4 hour Scale 8 hour Scale 4 Scale 8 Scale 16 Scale 40
2020 287 563 212 415 822 2,041
2021 276 541 204 399 789 1,961
2022 266 522 196 385 761 1,891
2023 258 505 190 372 737 1,831
2024 251 493 185 363 719 1,787
2025 246 482 182 356 704 1,749
2026 242 475 179 350 694 1,723
2027 239 469 176 346 684 1,700
2028 237 464 174 342 677 1,681
2029 234 459 173 338 670 1,664
2030 232 455 171 335 664 1,649
2031 230 451 170 332 658 1,635
2032 228 447 168 330 653 1,622
2033 227 444 167 327 648 1,610
2034 225 441 166 325 644 1,600
2035 224 439 165 324 641 1,592
2036 223 437 164 322 638 1,585
2037 222 435 164 321 635 1,579
2038 221 434 163 320 633 1,573
2039 221 432 163 319 631 1,568
2040 220 431 162 318 629 1,562

Flow Batteries
This IRP models two types of flow batteries, vanadium and zinc bromide. Other technologies are beginning to show up in the marketplace recently, including iron. Flow batteries have the advantage over lithium-ion as they do not degrade over time and have 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 assumes acquisition size of 25 MW of capacity with 4-hours in duration for each technology. Capital costs are $1,319 per kW for the vanadium in 2020 and costs fall 38 percent by
2030. Zinc bromide’s capital cost are $1,385 per kW, in 2020 falling by 44 percent by
2030. Fixed O&M costs are $58 per kW-year for vanadium and $66 per kW-year for zinc bromide, these cost increase with inflation. Round-trip efficiency for the vanadium is 70 percent and zinc bromide is 67 percent. Given Avista’s 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 9.7 shows the levelized cost per
kWh of capacity.
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Table 9.7: Flow Battery Levelized Cost $/kWh
Year Vanadium Zinc Bromide

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 into 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 be later used by pushing the air through an air turbine.
Liquid air has not been widely used in the electric sector but uses common technology
from other industries requiring liquefaction of other gases. This experience in the technology gives promise as a new technology that should benefit from short commercialization periods. Avista assumes a 25 MW capacity with 400 MWh hours of storage (16 hours). Another advantage of this technology is the ability to add storage
capacity by adding additional tanks and using the same turbine and liquefaction systems.
Avista estimates liquid air storage capital costs at $1,457 per kW (2020 dollars) and increasing with inflation rather than declining as the technology is not expected to reduce in real terms due to its using mature technology. Fixed O&M is $25 per kW-year and
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carry’s a $3.00 per MWh variable charge. The levelized cost of the storage is estimated to be $215 per kWh for 2020 and future years increase with inflation. Hydrogen/ Fuel Cell The idea of using hydrogen in the energy sector has been an option for the distant future for some time. 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. The
technology behind this storage concept is to use electric power to electrolyze water into hydrogen; the hydrogen would be stored in tanks and then converted back to power (and water) later using a fuel cell. This process would result in a 34 percent round trip efficiency. The ability to store hydrogen into tanks similar to liquid air means long duration times can be obtained. Hydrogen technologies are getting significant R&D in the
transportation and other sectors and may reduce its costs or increase its efficiency. It is also possible the transportation and other sectors could utilize the electric power system to create a cleaner form hydrogen to offset gasoline, diesel, propane, or even natural gas. The concept of offsetting natural gas led Avista to engage Black and Veatch to provide Avista’s Natural Gas IRP process estimates for renewable hydrogen options. The
assumptions and discussion are a result of this study. The main source of hydrogen today uses methane-reforming techniques to remove hydrogen from natural gas or coal. This technology is primarily used in the oil and gas industries, but results in similar levels of greenhouse gas emissions from the combustion
of the underlying fuels. If the hydrogen could be 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 hydrogen could also fall, but capital costs would remain steady.
Converting hydrogen back into power would require a hydrogen fuel cell. There are many fuel cell technologies on the market. Avista started Avista Labs which was ultimately sold to Plug Power which is a fuel cell manufacturer. There are also other fuel cell technologies, which convert natural gas into power such as Bloom Energy; but Avista is not modeling this conversion cycle, but rather hydrogen to power. It is also possible to co-
fire hydrogen with natural gas; although Avista is not studying this alternative in this IRP. Estimating the cost of the hydrogen storage concept requires multiple steps. For a four-hour duration project, the first step is the cost of the electrolysis system. For modeling purposes, the system would create 5,000 kilograms of hydrogen per day and have an
upfront cost of $6.7 million or $1,340 per kilogram plus cost to operate the facility would add $443,000 per year. Additional costs would be required for the power, variable O&M, excise taxes, and fees. For modeling purposes, variable O&M is $0.06 per kilogram and the energy price will depend on if the electrolizer is powered using retail power or wholesale and when the power is consumed. For example, if an independent company
was using electric power to create hydrogen for another end use the buyer of electric power would be paying retail rates; but if used as an electric energy storage, it would be treated similar to other storage technologies and be fueled by wholesale market prices.
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The efficiency of power to hydrogen is 50 kWh per kg in 2020, but improves to 48 kWh per kg by 2030.
Figure 9.2 shows the levelized price per kilogram of grid powered hydrogen using the efficiency and costs discussed above. These costs do not consider transportation or remarketing costs and assume power sourced from the wholesale energy market. Avista estimated the cost per kilogram would be levelized for power sourced with only solar (off
grid). These costs are higher than grid power due to lower utilization factors from only producing hydrogen when the sun was out. This concept could potentially be lower cost if technology can be configured to eliminate AC transformation. Thus, creating a pure DC closed loop system. Figure 9.2: Wholesale Hydrogen Costs per Kilogram

The second step in the hydrogen storage concept is to convert the hydrogen back to
power. For this conversion, a 25 MW fuel cell(s) would be assembled for a utility scale needs. Approximately 40 kWh of power will be created per kilogram of hydrogen, plus the hydrogen losses from its storage. The estimated capital cost for a fuel cell is $5,470 per kW with a four-hour storage vessel plus fixed O&M at $163 per kW-year. Table 9.7 shows
the all-in levelized cost of hydrogen storage including the fuel cell for 4-hour, 16-hour, and
40-hour storage lengths. Based on this analysis, the all-in cost for hydrogen storage is much higher than other options. Hydrogen likely has a future, but its likely place will be in limited applications until costs decrease, such as distributed solar with electrolysis for transportation related systems requiring frequent fueling.

Grid-Sourced Power Solar Sourced Power
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Table 9.8: Hydrogen Storage and Fuel Cell Levelized Cost $/kWh
Year 4-Hour 16-Hour 40-Hour
Woody Biomass Generation Woody biomass generation projects use waste wood from lumber mills or forest management. In the generation process, a turbine converts boiler-created steam into electricity. A substantial amount of wood fuel is required for utility-scale generation.
Avista’s 50 MW Kettle Falls Generation Station consumes over 350,000 tons of wood
waste annually or 48 semi-truck loads of wood chips per day. It typically takes 1.5 tons of wood to make one megawatt-hour of electricity, the ratio varies with the moisture content of the fuel. The viability of another Avista biomass project depends on the availability and cost of the fuel supply. Many announced biomass projects fail due to lack of a 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 $150 per kW-year for fixed costs and $3.17 per MWh of variable costs (2020 dollars). The levelized cost per MWh is $111 per MWh for a 2020 project.
Geothermal Generation
Geothermal energy provides predictable capacity and energy with minimal carbon dioxide emissions (zero to 200 pounds per MWh). Some forms of geothermal technology extract
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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 struggles to compete economically due to high development costs stemming from having to drill several holes thousands of feet below the earth’s crust. Ongoing geothermal costs are low, but the capital required for locating and proving a viable site is significant. In Avista’s last RFP,
one geothermal project was bid, and this led Avista to reconsider this option as a possible resource to include in the IRP. While a project was bid, it does have the hurdles previously discussed. The IRP estimates a future geothermal PPA is $80 per MWh in 2020 at the busbar. Nuclear Avista did not include nuclear plants as a resource option in prior IRPs 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. Nuclear resources could be in Avista’s future only if other utilities in the Western
Interconnect incorporate nuclear power in their resource mix and offer Avista an ownership share 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 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 $123 per MWh assuming capital costs of $4,518 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 available. Exclusion from the PRS analysis does not necessarily exclude non-modeled technologies from Avista’s future portfolio. The non-modeled resources can compete with resources identified in the PRS through competitive acquisition processes. Competitive acquisition
processes identify technologies to displace resources otherwise included in the IRP strategy. Another possibility is acquisition through PURPA. PURPA provides developers the ability to sell qualifying power to Avista at set prices and terms.5
5 Rates, terms, and conditions are available at www.avistautilities.com under Schedule 62.
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Landfill Gas Generation Landfill gas projects generally use reciprocating engines to burn methane gas collected
at landfills. The Northwest has developed many landfill gas resources. The costs of a landfill gas project depend on the site specifics of a landfill. The Spokane area had a project on one of its landfills, but it was retired after the fuel source depleted to an unsustainable level. Much of the Spokane area no longer landfills its waste and instead uses the Spokane Waste to Energy Plant. Nearby in Kootenai County, Idaho, the
Kootenai Electric Cooperative developed the 3.2 MW Fighting Creek Project. Using publically available costs and the NPCC estimates, landfill gas resources are economically promising, but are limited in their size, quantity, and location. Many landfills are considering cleaning the landfill gas to create pipeline quality gas due to falling wholesale electric market prices. This form of renewable gas has become an option for
natural gas 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 seven to ten 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. These facilities tend to be significantly smaller than most utility-scale generation projects, at less than five megawatts. Most 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. Anaerobic digesters may opt to clean
the gas to make to pipeline quality to offer a clean gas alternative. Small Cogeneration Avista has few industrial customers with loads significantly large enough to support a cogeneration project. If an interested customer was inclined to develop a small
cogeneration project, it could provide benefits including reduced transmission and distribution losses, shared fuel, capital, and emissions costs, and 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 determined feasible.
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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 retrofit or creation 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 particular project. The best method for the utility to acquire this technology is through the PURPA process or in 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 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 with be permanent carbon 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 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 heat for their end use of 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 called the Eco-District. The Hub facility will contain a central energy plant. It can generate, store, and share thermal and electrical energy with a combination of heat pumps, boilers, chillers, thermal, and electrical storage. The Hub will control all electric consumption for the campus and balance 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. Bonneville Power Administration For many years, Avista received power from the Bonneville Power Administration (BPA) through 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 does engage 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
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$79.80 per MWh6. Since this offering is short-term and variable, Avista does not consider it as a viable long-term option for planning purposes, but 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. Existing Resources Owned by Others
Avista purchased long-term energy and capacity from regional utilities in the past, specifically the Public Utility Districts in Mid-Columbia region. Avista contracts are currently discussed in Chapter 4, but extensions or new agreements could be formed. It is also possible in the event other utilities are long on capacity to develop agreements to strengthen Avista’s capacity versus load positon. Since these potential agreements are
based on existing assets, prices depend on future markets. Avista is modeling for this IRP the possibility of an up to 75 MW extension of existing agreements, but the cost and actual quantities available 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.
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 it as a fuel in natural gas-fired turbines due to higher efficiency in end use
in customer’s homes. Hydroelectric Project Upgrades and Options
Avista continues to upgrade its hydroelectric facilities as shown in Figure 9.3. The latest hydroelectric upgrade added ten megawatts to the Nine Mile Falls Development in 2016.
Avista added 46.8 aMW of incremental hydroelectric energy between 1992 and 2016.
Upgrades completed after 1999 can qualify for the EIA, thereby reducing the need for additional renewable energy options. Further, any upgrade can qualify for CETA if it meets the requirements as a clean energy resource.
Construction of the Spokane River hydroelectric project occurred in the late 1800s and
early 1900s, when the priority was to meet then-current loads. The developments therefore do not capture a majority of 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 developments and estimated costs for generation upgrade
options. Each upgrade option should qualify for the EIA renewable energy goal. These
6 https://www.bpa.gov/Finance/RateInformation/Pages/Current-Power-Rates.aspx.
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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 9.3: Historical and Planned Hydro Upgrades
Post Falls At the time of publishing the 2017 IRP, the Post Falls project was undergoing an analysis
to determine the best course of action to maintain the facility. Two primary options were proposed. The first option is to replace existing equipment with similar size. The second option is to increase the capacity of the project by eight megawatts. Within this IRP modeling process, the PRiSM model can choose to upgrade the facility in 2027. Upgrading the facility would increase generating capacity by 4.5 aMW and increase winter
peak generation by 3.8 MW for an additional cost above replacing with in-kind equipment. 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.
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The 2012 study considered three alternatives. The first replaces the existing four-unit powerhouse with four larger units totaling 120 MW, increasing capacity by 32 MW. The
other two alternatives develop a second powerhouse with a penstock beginning from a new intake structure downstream of the existing saddle dam. One powerhouse option was a single 68 MW turbine project. The second was a two-unit 152 MW project. The best alternative in the study was to add the single 68 MW unit. Table 9.9 shows upgrade costs and characteristics. Avista will need to refine this study for future analysis as the existing
machinery in the powerhouse approach their end of life. Monroe Street/Upper Falls Second Power House Avista replaced the powerhouse at its Monroe Street development on the Spokane River in 1992. There are three options to increase its capacity. Each would be a major
undertaking requiring substantial cooperation with the City of Spokane to mitigate disruption in Riverfront and Huntington parks and downtown Spokane during construction. The upgrade could increase plant capacity by up to 80 MW. To minimize impacts on the downtown area and the park, a tunnel drilled on the east side of Canada Island could avoid excavation of the south channel to increase streamflow to the new
powerhouse. A smaller option would add a second 40 MW Upper Falls powerhouse, but this option would require south channel excavation. A final option would add a second Monroe Street powerhouse for 44 MW. All project options were removed for this IRP due to the disruption to the Riverfront Park and the downtown area. Avista may reconsider this analysis in future partnership with the City of Spokane.
Cabinet Gorge Second Powerhouse Avista is exploring the addition of a second powerhouse at the Cabinet Gorge development 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. This resource does not add any peak capacity credit due to the water right limitations of the license. The resource only creates additional energy during spring runoff. Table 9.9: Hydroelectric Upgrade Options

Resource Monroe Street/Upper Falls Lake Gorge
Incremental Capacity (MW) 80 68 110
Incremental Energy (MWh) 237,352 202,592 161,571
Incremental Energy (aMW) 27.1 23.1 9.2
Peak Credit (Winter/ Summer) 31/0 100/100 0/0 Capital Cost ($2020 Millions) $171 $165 $260
Levelized Energy Cost ($2020/MWh) $92 $84 $196

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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 State.
No costs are presented in this section, as pricing is sensitive to third-party suppliers, but
presents an overview of the concepts. Estimated cost are including the portfolio modeling discussed in Chapter 11. Rathdrum CT Supplemental Compression
Supplemental compression is a new technology developed by PowerPhase LLC that
increases airflow through a CT compressor 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 corresponding to a five MW increase in output. Rathdrum CT Inlet Evaporation
Installing a new inlet evaporation system will 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. At this time, 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 materializes in a cost by changing otherwise more efficient operations. For Avista this is challenging 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 equips our real-time operations team in managing when to dispatch resources. For this IRP, wind will add approximately $5 per MWh in operating cost inefficiencies and
solar $1.80 per MWh based on the 2007 study. Avista’s 2007 study is still relevant due to
scenario analysis performed including pricing similar to prices of today along with a similar resource portfolio. With an EIM in place, Avista expects these costs to lower by 40 percent, this result was also part of the 2007 analysis when shorter trading blocks were studied. Avista believes these costs will increase with additional generation on the system
and will need to study these issues in future IRPs when tools with sub-hourly modeling of
Avista’s unique system are completed.
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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 of the produced energy each hour. Ancillary Services Values
Many of the resources discussed in this chapter may provide benefits to the electrical system beyond traditional energy and capacity (for reliability). 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 resources outages on the system. Within the reserve requirement, 22 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 hydroelectric generation. 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;
these include 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 clarify 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
software systems. Further, Avista needs to 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. Avista is still developing the
ADSS model to provide this complete analysis. In the fifth TAC meeting, 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. Although, as Avista enters a future with additional on-system renewables and
an EIM, these estimates will need to be revised. With this in mind, Table 9.10 outlines the
assumed values for Ancillary Service benefits for new construction projects.
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Table 9.10: Ancillary Services Value Estimates (2020 dollars)
Resource $/kW-yr
Resource ELCC Analysis
Avista conducted substantial research and time in studying the impact of resources effect on resource adequacy. Throughout this process, Avista learned that the quantity, location, and mixture of resources has a substantial effect on the benefit each resource can provide. 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 re-charging;
but as its proportion gets larger, there is not enough energy to refill the storage device for later dispatch as shown in the E3 study for resource adequacy7. When coupled with renewable energy storage the combined resources may increase our 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.
Avista used 1,000 simulations of Avista 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 lower Loss of Load Probability (LOLP) using the
Avista Reliability Assessment Model (ARAM). The model is first simulated using a reliable
system with a set of new natural gas-fired CTs to meet future load obligations. Then the gas turbines are removed and replaced with each of the resources in Table 9.11. The percentage shown in the table is the percent of natural gas turbines assumed the replacement resource would offset. After PRiSM selects the PRS, the specific resource
selection is studied for LOLP. If not meeting the 5 percent LOLP metric due to intra
reaction between the resources, the resulting/effective planning margin increases and a new strategy selected for comparison to the reliability metric.
7 Appendix F, Resource Adequacy in the Pacific Northwest, page 54.
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Table 9.11: Peak Credit
Resource Peak Credit (percent)
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Other Environmental Considerations
Natural Gas Production and Transportation Greenhouse Gas Emissions All generating resources have an associated emissions profile, either when it produces energy or when it was constructed. For this IRP Avista models associated emissions with the production of energy. Future IRPs may consider the emissions associated with the
manufacturing and construction of the facility. Other potential studies could be from the indirect greenhouse gas emissions from biomass and coal production. The only indirect greenhouse gas emissions resource studied in this plan is natural gas. Natural gas is assumed to emit 119 pounds of greenhouse gas emissions equivalent 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. The Washington State customer’s share of generation includes these potential emissions priced at the social cost of carbon for resource optimization. The additional emissions are 0.829
8 Net of transmission losses.
9 Based on Monroe Street 2nd Powerhouse.
10 This resource 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 modelled solar plus storage where
the storage resource could be charged with non-solar as well to reflect long-term utility operations
11 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
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percent12. Avista sources its natural gas for power generation from the province of Alberta via the GTN pipeline and the province tracks these emissions. To account for these
emissions, Avista is using a set of official reports as accounted for by the Canadian and United States governments. These 2017 reports were submitted to the National Energy Board (NEB) in Canada and PHMSA (Pipeline and Hazardous Materials Safety Administration) in the U.S. The reports carry penalties for falsehoods and are subject to review and audit.
There are three pipelines carrying natural gas from the Canadian production areas to the U.S. demand markets. The first is Nova Gas Transmission (NGTL) and it is the largest set of pipelines connected to the production fields bringing over eight billion dekatherms of energy to the market in 2017. Its carbon equivalent fugitive emissions are roughly five
million tons or 0.767% of the overall energy produced. Foothills pipeline delivers 1.5 billion dekatherms of energy with a reported 0.678% fugitive emissions rate. Finally, Gas Transmission Northwest (GTN) is the backbone of supply of natural gas to our generation facilities and in 2017 alone delivered nearly eight hundred million dekatherms of volume with an emissions rate of 1.758%. As a system the overall emissions for 2017 is 1.164%
and includes CO2, CH4 and N2O emissions all converted to metric tons of carbon dioxide equivalents using 100-year Global Warming Potentials as found by the Intergovernmental Panel on Climate Change (IPCC). The IPCC is the United Nations body for assessing the science related to climate change. A summary of these figures and their sources can be found in Table 9.12: Table 9.12: Natural Gas Fugitive Emissions
2017 Volume reported, Dth volume to tonnes CO2 reported, tonnes CO2 Percent
Nova Gas Transmission, NGTL13 8,202,460,151 435,430,053 3,341,551 0.767%
14 1,527,266,974 81,075,425 549,489 0.678%
15 794,764,490 42,190,311 741,635 1.758%
Greenhouse Gas Emissions for Storage Resources Avista considers emissions from the acquisition of market power. As outlined in Chapter
10, the greenhouse gas emissions associated with power purchases is the average emission rate for the northwest area for this IRP. Avista conducted additional analysis to
12 The IRP analysis included 0.783 percent for these emissions from Avista’s draft analysis; the 0.829 percent number represents the final estimate.
13 Volume: National Energy Board (NEB) Pipeline profiles data, neb-one.gc.ca; Emissions: Canadian GHG reporting program (GHGRP), climate-change.canada.ca.
14 Volume: National Energy Board (NEB) Pipeline profiles data, neb-one.gc.ca; Emissions: Canadian GHG reporting program (GHGRP), climate-change.canada.ca.
15 Volume: 2017 annual report to PHMSA, form 7100.2-1 (rev 10-2014), Part C, phmsa.dot.gov; Emissions: 2017 submission to EPA, epa.gov.
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estimate the emissions associated with market purchases for energy storage resources. When power is stored from market power, it may have associated greenhouse gas
emissions. Many other IRPs assume power stored is emission free, where its emissions are based on the source of the power stored. In a future where market purchases are used to store the power, the power will likely be assigned emissions from the market’s emission intensity. Although the intensity of those emissions will differ from the market as the storage resources is only charging in certain periods. To understand this difference,
Avista modeled the hourly emissions intensity of the northwest energy supply and matched those hours when a storage device was charging16. The results show when suppling a storage facility with market power will ultimately have lower emissions profiles than the overall energy market, this is because the market typically charges in lower price periods when more renewables are available. The amount of reduction as compared to
the market depends on the duration of the storage resource, but on average storage emissions are 30 percent less than average market emission rates after 2030. Other Environmental Considerations There are other environmental factors involved when siting and operating power plants.
Avista considers these cost in the siting process. For example, new hydroelectric projects or modifications to existing facilities must be made in accordance with their operating license, and if new facilities require operations outside this license, the license would reopen. When siting solar and wind facilities, developers must have approvals from local governing boards to make sure all laws and regulations are kept.
If Avista sites a new natural gas facility, it will have to meet state and local air requirements for its air permit. These requirements are at levels these governing bodies find fitting for their communities. At this time, Avista is not evaluating emissions costs outside of these considerations.

16 This analysis uses the deterministic version of the expected cases market analysis.
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Market Analysis
The energy policy trajectory within the Western Interconnect is shifting toward clean generation. Several states, including Washington and California, passed 100 percent clean energy goals. These policy changes have a dramatic effect on the wholesale power
market. Previous IRPs focused on carbon pricing methodologies driving wholesale power
prices upward, but the new energy policies focusing rather on the quantities of renewable energy will likely push prices lower and cause more volatility in periods without significant renewable energy.
The market fundamental analysis is one of the most important factors to consider when
selecting a resource strategy to serve Avista’s customers over the next 25 years. Avista uses the forecast of future market conditions to optimize its resource portfolio options. The Company uses electric price forecasts to evaluate the net value of each 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 developed by Energy Exemplar. This model includes generation resources, load estimates, and transmission links within the Western Interconnect. This chapter outlines the modeling
assumptions and methodologies used for this IRP and includes Aurora’s primary function of electric market pricing (Mid-Columbia for Avista), but also operating results from the analysis. The Expected Case is a forecast defined using the best available information on policies and resource costs under average conditions for renewable energy. This chapter also presents the results to four additional pricing scenarios.

Section Highlights
• Solar and wind dominate future generation across the west, but natural gas, coal, and storage will keep the system resource adequate. By 2045, 96 percent of generation in the Pacific Northwest will be carbon free.
• Greenhouse gas emissions will fall to modern history lows due to expansion of renewables and coal plant retirements. By 2045, emissions will be 62 percent less than in 1990.
• The 20-year wholesale electric price forecast (2021-2040) is $26.44 per MWh.
Expansion of renewables will lower mid-day prices, but evening and night prices will be at a premium compared to pricing in today’s environment.
• Natural gas prices will remain low; the 20-year Stanfield natural gas forecast (2021-2040) is $3.47 per dekatherm.
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Electric Marketplace
Avista simulates the Western Interconnect electric system for its IRP planning; shown as WECC1 in Figure 10.1. The remaining areas 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 IRP’s market simulation models each operating hour annually between 2021 and 2045. For each hour, the model simulates both load and generation dispatch for fifteen
regional areas or zones within the west. Avista’s load and a majority 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 the zones and reflect operation 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. Avista’s focus of this power system modeling is the resulting wholesale electric market price forecast for the Northwest zone or Mid-Columbia market place. The Aurora model estimates its electric prices by using an hourly dispatch algorithm to
match the load in each zone with the available generating resources. Resources selected
to dispatch after considering its fuel availability, fuel cost, O&M cost, dispatch incentives/disincentives, and operating constraints. The electric price is the last generating resource required to meet area load marginal operating cost. The IRP uses these prices to value each of its resource (both supply and load side) options and select
these as a least reasonable cost plan to meet its load obligations. Avista also conducts a
stochastic analysis for its price forecasting where certain assumptions use a distribution of 500 potential inputs. For example, randomly drawing hydro conditions from an equal 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 and resulting dispatch and greenhouse gas emissions profiles for the west for the 500 stochastic studies.
1 WECC is an acronym for Western Electrical Coordinating Council. WECC coordinates reliability for the entire Western Interconnect.
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Figure 10.1: NERC Interconnection Map
Table 10.1: AURORAXMP 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
Western Interconnect Loads
Each of the fifteen zones requires hourly load data for all 25 years of the forecast plus 500 different stochastic studies to account for weather variation. Future loads may not look like past loads from an hourly shape point of view due to the continual increase in
electric vehicles and rooftop solar generation. 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 for only power price modeling. Therefore, Avista uses the following methods to
derive its regional load forecast for power price modeling.
To start the process, Avista relies on Energy Exemplar’s demand forecast included with the software package. This forecast include an hourly load shape for each region along with annual changes to both peak and energy. The hourly load shape uses historical data each control area and the growth rates use publically available forecast information for
each region. Figure 10.2 shows this base forecast below as the black dotted line. Over
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the full Western Interconnect, the load used in the model grows at 0.79 percent per year. Avista adjusts this forecast to account for changes in electric vehicle penetration and net-
metered generation, such as rooftop solar. These adjustments change the forecast to approximately 0.85 percent per year. Electric Vehicle load grows at 12 percent per year and net-metered generation grows at 7 percent per year. Within the year, the hourly load shapes adjust to reflect charging patterns of both residential and commercial vehicle charging in addition to the majority of net-metered generation being modeled as fixed roof
mount solar panels. Figure 10.2: 25-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 data from 2007 to 2015, the same assumption from the 2017 IRP2. These load variations
change the loads for each of the 500 simulations of the electric price forecast. To maintain
consistent west coast weather patterns, 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 excursions
witnessed by the electricity grid. The additional accuracy from modeling loads this way is
2 2017 Electric IRP pages 10-15 to 10-16.
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crucial for understanding wholesale electricity market price variation. It is vital for understanding the value of peaking resources and their use in meeting system variation.
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;
• Resource retiring;
• New resources for capacity;
• New resources for renewable energy compliance; and,
• Fuel prices, fuel availability, and operating availability of each resource within the system. Energy Exemplar, the vendor of Aurora, provides a database of existing generating
resources. The database includes location, size, and estimated operating characteristics for each resource. When a resource has a publicly scheduled retirement date or is part of a provincial phase-out plan, these resources are retired for modeling purposes. Avista does not include estimated retirements of any resources. Rather, plants that become less economic in the forecast will dispatch fewer hours. Specifically, the northwest includes a
number of expected coal plant retirements including Boardman, Colstrip3, North Valmy,
and Centralia. Figure 10.3 shows the total retirements included in the electric price forecast. Approximately 20,000 MW of coal, 7,000 MW of natural gas, 5,000 MW of nuclear, and 750 MW of other resources including biomass, hydro, and geothermal are known to retire by the end of 2045.
3 This IRP modeled Colstrip Units 1 and 2 to be offline at the end of 2019 and one of the remaining units is modeled to go offline at the end of 2025.
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Figure 10.3: Cumulative Resource Retirement Forecast
New Resource Additions In order to meet future load growth, clean energy goals, and to replace retired generation,
a new generation forecast must include resources to meet peak load and renewable portfolio standards. 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 third party consultants. The process begins with a forecast of new generation by resource type from
the third party consultant. Consultants with multiple clients and dedicated staff can research new resource costs and operating characteristics with greater efficiency then Avista on likely resource construction in the west, especially in areas where Avista has no presence or local market knowledge. The next step in this process adjusts the clean energy additions to reflect changes in state policies for additional renewable energy. The
last step runs the model for 500 simulations to see if each area can meet a resource adequacy test. The goal is for each area to serve all load in at least 475 of the 500 iterations. Figure 10.4 shows the added generation included in this forecast. This forecast includes
approximately 250 GW of added resources including 110 GW of supply side solar, 50 GW of wind, 30 GW of natural gas combined cycle CTs, 24 MW of storage4, 20 GW of natural gas CTs, and 4 GW of other resources including hydro, biomass, and geothermal.

4 Storage energy to capacity ratio averages 3 hours in 2021 and increases to 6 hours by 2045. This change is to reflect technological advances in duration of batteries or other storage technologies.
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Figure 10.4: Western Generation Resource Additions (Nameplate Capacity)
Within the northwest region5, additional resources are required to meet both resource
adequacy and meet clean energy requirements (both mandates and customer choice)
through 2045. Resource adequacy requires an estimated 5 GW of additional natural gas turbines and 3 GW of storage. Regional clean energy targets require 28 GW of solar, 14 GW of wind, and 2 GW of other renewable technologies. Generation Operating Characteristics
Avista makes a number of changes to the resources available to serve future loads to account for Avista’s specific expectations of the marketplace 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. In fact, between 2003 and 2019 the R2 between natural gas and on-peak Mid-
Columbia electric prices is 0.89, indicating a strong correlation. This is due to the fact the
natural gas-fired generation facilities were typically the marginal resource in the northwest with the exception of times when hydro generation was high due to water flow. In addition, natural gas generation met 30 percent of the load in the Western Interconnect in 2018. With the large increases in intermittent renewable energy from solar and wind in the west,
the number of hours where natural gas-fired facilities will set the marginal price is likely
to decline. For modeling purposes, Avista uses monthly natural gas prices for dispatch and changes these prices based on a distribution of prices for each of the 500 stochastic forecasts.
The forecasts begins with the Henry Hub forecast. Henry Hub is the location used for
5 The northwest includes Washington, Idaho, Oregon, and Montana.
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most natural gas transactions in North America for price hedging. Since Avista is not equipped with fundamental forecasting tools, nor is it able to track all natural gas market
dynamics, it uses three sources for these forecasts. The first source is forward market prices as of June 12, 2019. The model uses these prices exclusively for 2021, but Avista lowers the forward market price weight compared to the other two sources to 75 percent in 2022, 50 percent in 2023, 25 percent and 2024, and zero thereafter. The other two sources of forecasted Henry Hub prices are from two consultants with the capability to
follow the supply and demand changes of the industry. The model weights these two forecasts evenly in the forward estimate through 2040. Between 2040 and 2045, prices escalate at the last two years growth rate. Figure 10.5 shows each of the components included in the Henry Hub natural gas price forecast annually. The 25-year nominal levelized price of natural gas is $4.36 per dekatherm and the 20-year nominal levelized
price is $3.99 per dekatherm. 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 use supply basins where prices could be either higher or lower than the Henry Hub.
Typical basins for the Northwest include Sumas for coastal plants on the northwest pipe
system. Plants on the GTN pipeline could use prices from either AECO, Stanfield, or Malin depending on their contractual rights. Table 10.2 shows these basin differentials as a percent change from Henry Hub. In addition, this table includes basin nominal levelized prices for both 20 and 25 years for selected basins.

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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 167 of 259
Table 10.2: Natural Gas Price Basin Differentials from Henry Hub
25 yr $3.88 $4.02 $3.83 $3.20 $3.90 $4.14
20 yr $3.51 $3.64 $3.49 $2.89 $3.53 $3.77 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 to allow prices to experience price excursions, but 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 natural gas price change in price is drawn from the
distribution. The lognormal distribution shape and variability uses historical monthly volatility. Using the lognormal distribution allows for 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 nominal levelized price for 20 years is $3.47 per dekatherm compared to the inputted price of $3.51 per dekatherm. These values may converge with a larger sample size. The median
price is also lower at $3.35 per dekatherm. The lower price illustrates the skewness of the
distribution to bias prices higher. Another component of the stochastic nature of the forecast is the growth in variability. In the first year, prices vary 13 percent around the mean, or the standard deviation as a percent of the mean. By 2040, this value is 32 percent and 35 percent by 2040. Avista uses higher variation in later years because the
accuracy and knowledge of future natural gas prices is more uncertain.
Another way to visualize Avista’s natural gas price assumption is in Figure 10.7. This charge shows the 20-year nominal levelized prices for Stanfield in a histogram view to demonstrate the skewness of the natural gas price forecast.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 168 of 259
Figure 10.6: Stochastic Stanfield Natural Gas Price Forecast
Figure 10.7: Stanfield Nominal 20-Year Nominal Levelized Price Distribution

Average
25th Percentile
50th Percentile
95th Percentile
Input Forecast
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 169 of 259
Regional Coal Prices Coal-fired generation facilities are still an important part of the resource mix across the
Western Interconnect. In 2018, coal met 21 percent of Western Interconnect loads, although this amount was 36 percent in 2001. Coal pricing is typically different from natural gas pricing. Natural gas is a commodity delivered by pipeline, whereas coal delivery can be by rail or by conveyor. Typically, the coal contracts are longer term and supplier specific. Avista uses the Energy Exemplar coal forecast as they review FERC
filings for each of the coal plants to determine historical pricing, and they use the EIA Annual Energy Outlook reports for future pricing. Future coal pricing has price uncertainty like natural gas prices. Although its effect on market clearing pricing is less as coal-fired generation rarely sets on the margin in Avista’s
marketplace. Labor, steel cost, and transportation costs drive coal price uncertainty; transportation is the primary coal price driver. There is also uncertainty in fuel suppliers as the coal industry is restructuring. Given the small effect on market prices, Avista chose not to model this input stochastically. Hydroelectric The Northwest U.S., British Columbia, and California have substantial hydroelectric generation capacity. Hydroelectric resources served 57 percent of load in the Northwest. Although over the entire Western Interconnect, hydroelectric generation serves 24 percent of load. A favorable characteristic of hydroelectric power is its ability to provide
near-instantaneous generation up to and potentially beyond its nameplate rating. Hydroelectric 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 hydroelectric generation is its variability and limited fuel supply.
This IRP uses an 80-year hydroelectric data record. The study provides monthly energy levels for the region over an 80-year hydrological record spanning 1928 to 20096. Many IRP studies use an average of the hydroelectric record, whereas stochastic studies randomly draw from the record, as the historical distribution of hydroelectric generation is
not normally distributed. Avista uses both methodologies. Figure 10.8 shows the average hydroelectric energy as 14,750 aMW in the northwest for 2021, 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 11,564 aMW (-22 percent) and a 90th percentile water year of 17,600 aMW (+19 percent). The
EIA reports detailed generation back to 2001. This was a historically low year with 11,098 aMW generated, but in 2018, 15,930 aMW was generated. Over the 18-year period, the average was 14,875 aMW and is right in line with the 80-year historical average. Although, generation from 2009 and 2018 averaged 15,411 aMW.
Aurora maps each hydroelectric plant to a load zone, creating a similar energy shape for all plants in the load zone. For Avista’s hydroelectric plants, Aurora uses the output from its own proprietary software with a more accurate representation of operating
6 The Bonneville Power Administration provides the underlying data use for regional hydroelectric data.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 170 of 259
characteristics and capabilities. Aurora represents hydroelectric 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 hydroelectric generation into peak load hours to maximize the value of the system consistent with actual operations. Figure 10.8: Northwest Expected Energy
Wind Variation and Pricing Wind is a growing generation source to meet customer load. As of 2018, 7 percent of regional load was met by wind compared to 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 and its effect on the other generation resources and the effect to
electric market clearing prices. Energy Exemplar made significant progress populating a larger database of historical wind data points throughout North America. This IRP leverages their 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 the change in generation hour-to-hour and also includes seasonal effects of the generation. To simplify the amount of data Avista, developed 15 different annual hourly wind generation shapes that are randomly drawn for each year of the 25-year forecast. By
capturing this volatility, the model can properly estimate hours with oversupply compared to using monthly average generation factors.
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 171 of 259
Solar Like wind, solar is quickly increasing its market share in the Western Interconnect as a
way to serve loads. Solar served 6 percent of the total requirement in 2018, but was just 2 percent in 2016 (both of these estimates exclude behind the meter solar generation). With Avista’s acquisition of solar, along with its quick rise as a dominate energy supplier, better and more information is available to properly model the generation. In previous IRPs, limited solar shapes were available for each of the areas within the Aurora model,
but now multiple shapes with multiple configurations are available. The model has data for fixed panels and single axis technology types along with multiple locations within an area. As solar continues to grow, additional details will be available and incorporated into future IRP modeling. One of these new techniques should include multiple hourly solar shapes similar to that used with wind, so that the model can account for solar variation
due to cloud cover. Other Generation Operating Characteristics Avista uses the Energy Exemplar database assumptions for all other generation types, except for its owned and controlled resources. For Avista’s resources, more detailed
confidential information is used. The other major difference requiring a discussion for use of the Aurora software is the method of handling generation forced outages. Forced outage and mechanical failure is a common problem for all generation resources. Typically, the modeling for these events is de-rated generation. This means the available output is lowered to reflect the outages. Avista uses this method for solar, wind,
hydroelectric, 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 and keep 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’s effect on the Mid-Columbia market and the resulting negative price effect. Negative pricing occurs when there too much generation that wants to dispatch and not enough load to serve with it. This occurs most often in the Northwest when much of the hydro system is running in the spring months due to run off and wind projects are also generating and do not have
the economic incentive to shut off due to their requirement to generate for PTC, REC, or PPA reasons. Hydro resources are dispatchable, but they may not be able to dispatch off due to total dissolved gas issues they may create if water is spilled instead of generated. This phenomenon will likely increase as more wind and solar generation is added to the system where there are PTC’s in place or incentives to generate at zero pricing due to
clean energy generation requirements. To model this effect in Aurora, Avista must change the economic dispatch prices for several resources that have dispatch drivers beyond fuel costs. The first change Avista made is to change the hydro dispatch order. This means making
hydro resources a “must run” resource or last resource to turn off. To do this, hydro
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 172 of 259
generation is assigned a negative $30 per MWh price (2018 dollars)7. The next change is to assign an $8 per MWh (2018$) reduction in cost for renewable resources to reflect
their preference for meeting state renewable portfolio standards (RPS). The last adjustment is to include a Production Tax Credit (PTC) for resources with this benefit. After these adjustments, the model will turn off resources when there is too much generation and the last resource turned off sets the marginal price.
There could be potential solutions to reducing the amounts of negative prices hours going forward. One method would reduce the incentive to generate when the power is not needed. Meaning, counting the “spilled” generation toward meeting the clean energy requirements or meeting the generation requirements for the PTC. Other solutions are to develop load-based options that can take advantage of wholesale market and increase
their requirements. The third method is storage. As storage cost decreases and oversupply increases, 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 can see the pricing effects in the market for its economic analysis. Without these adjustments, expected generation from renewable
resources may be over estimated by not including the hours of the year it will be curtailed. Greenhouse Gas Pricing Many states and provinces enacted greenhouse gas emissions reduction programs. Other states are in discussion for such programs. Some states have trading mechanisms
while others chose clean energy targets. From a modeling perspective, Aurora can model either, but different policy choice can result in dissimilar impacts to electric wholesale pricing. Clean energy target programs, such as Washington’s, generally depress prices due to increasing amounts of low margin priced resources Programs like California’s cap and trade push wholesale prices upwards. Avista includes known programs in California,
British Columbia, and Alberta in its modeling as a carbon “tax.” The carbon tax means the model includes a specified price on emissions. At the time of the development of this analysis, Oregon was close to enacting a cap and trade program. Avista proactively included this trading mechanism for modeling purposes even though Oregon ultimately failed to pass a cap and trade program in the 2019 legislative session. To account for
these emissions, Avista modeled a cap on emissions of 3.6 million tons within Oregon. Although, this modeling cap was rarely enforced due to the influx of renewables from other environmental policies.

7 These plants cannot be designated with a “must run” designation due to the must run resources would require resources to dispatch at minimum generation and for modeling purposes, hydro minimum generation is zero in the event of low flows.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 173 of 259
Electric Resource and Emissions Forecast
Avista forecasts a major shift to clean energy resources across the Western Interconnect in the next 25 years. Figure 10.9 shows the historical and forecast generation for the U.S. portion of the Western Interconnect. In 2018, 41 percent of load is served by clean energy,
increasing to 65 percent by 2030, and 81 percent by 2045. To achieve this shift in energy,
while also serving new loads, solar and wind production will need to increase at the expense of coal and natural gas. Although without development of significant new storage technologies, thermal resources are required to help meet system needs during peak weather events, especially in the Northwest winter.
Figure 10.9: Generation Technology History and Forecast
The northwest will also have 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 2018, 77 percent of the northwest generation was clean generation, but by 2030, the plan expects it to increase to 87 percent and 96 percent by 2045 as shown in Figure 10.10. Achieving these ambitious clean energy goals will require a doubling of wind generation
and an 18 fold increase in solar energy from the 2018 generation levels. This results in solar providing 11 percent of future generation and wind 22 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 solar’s price competitiveness.

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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 174 of 259
Figure 10.10: Northwest Generation Technology History and Forecast

Due to the large increases in renewable energy and limited long-term economic storage
solution, this forecast expects renewable generation curtailments even with the pricing preferences included in the model. Figure 10.11 below shows how a Northwest solar and wind plant’s dispatch will change on an annual average basis over the 500 simulations. By 2030, solar dispatches 3 percent less and wind 1 percent less; but by 2045 solar is 10 percent lower and wind 13 percent lower on average. Also shown on the chart is the 10th
and 90th percentiles to illustrate how production could change under different conditions of the 500 simulations.
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 175 of 259
Figure 10.11: Wind and Solar Curtailment Forecast
Regional Greenhouse Gas Emissions Greenhouse gas emissions are likely to significantly decrease with the retirement of coal
generation facilities and solar/wind resources displacing additional natural gas generation. Avista estimates greenhouse gas emissions for plants within the U.S. Western Interconnect at approximately 230 million metric tons in 2017, which is very close to the 1990 emissions levels of 227 million metric tons. Avista obtained historical data back to 1980; the emissions minimum since 1980 was in 1983, at 154 million metric tons.
In our market modeling, Avista only tracks emission where the emissions are sourced and does not estimate how emissions will be assigned by each state for transfers, such as emissions generated in Utah for serving customers in California. Figure 10.15 shows the percent totals. The largest emitters are Arizona and Colorado, followed by California,
Utah, and Wyoming. The four northwest states generate 14 percent of the total emissions. Avista expects emissions to quickly fall by 20 percent by 2021 compared to 2017 due to coal plant retirements. By 2045, emissions fall by 62 percent compared to 1990 levels as shown in Figure 10.13. All states will have a reduction in emissions in this forecast. The
greatest reductions by percentage are Washington (91 percent), Oregon (85 percent), and New Mexico (75 percent). The greatest reductions by tons are Colorado (23 MMT), Arizona (22 MMT), and Wyoming (18 MMT).
Solar Expected Forecast Solar 10th PercentileSolar 90th Percentile Wind Expected ForecastWind 10th Percentile Wind 90th Percentile
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 176 of 259
Figure 10.12: 2017 Greenhouse Gas Emissions
Figure 10.13: Greenhouse Gas Emissions Forecast
Regional Greenhouse Gas Emissions Intensity To understand the emissions impacts of Avista’s market purchases, Avista uses regional
emissions intensity to estimate associated emissions from these short-term acquisitions.
Avista uses the values shown in Figure 10.14 for each of the 500 simulations. The chart below shows the mean, 25th percentile, and 75th percentile. The emissions are included from Washington, Oregon, Idaho, Montana, Utah, and Wyoming. Emissions intensity will
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 177 of 259
fall as additional renewables are added and coal plants retire, but the intensity rate will depend on the variation in hydro production. The locations for Avista potential market
purchase radius is consistent with Washington’s energy and emissions intensity report but is higher than Avista’s likely counter parties for market purchases. To address this inconsistency, the four northwest states are shown in the yellow dots with lower emission intensity rates, although over time, the two values converge.
Figure 10.14: Northwest Regional Greenhouse Gas Emissions Intensity
Electric Market Price Forecast
This chapter describes the major inputs and assumptions the Aurora model uses to
generate its electric price forecast. It also includes results for how resources will dispatch
and how emissions change in the future with changes to state environmental policies. The next section describes the pricing effects to the Mid-Columbia wholesale market. These prices are an important part of the IRP as they determine the economic value of each resource for a comparison analysis against other demand and supply side
resources. Mid-Columbia Price Forecast Two Expected Case forecasts are studied for the IRP. The first is the deterministic case which has variation in assumptions and the second study is the stochastic case where
inputs vary. Each study uses hourly time steps between 2021 and 2045 for a simulation
of over 219,000 hours. This process is time consuming when conducted 500 times. Running the Expected Case 500 times took over two weeks of continuous processing to complete. Time constraints limit the number of market scenarios.
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 178 of 259
The annual prices from both studies are shown in Figure 10.14 for flat pricing, meaning the average of all hourly prices over the year. 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 track natural gas pricing. The 25-year nominal levelized price of the deterministic study is $26.10 per MWh and $27.86 per MWh for the stochastic study, see Tables 10.3 and 10.4. Table 10.4 also includes a new price labeled as super peak evening. This price represents
weekday prices between the hours of 4 pm and 10 pm. These prices represent hours where solar output is falling and prices will rise to encourage dispatch of other resources. Figure 10.15: Mid-Columbia Electric Price Forecast Range
Table 10.3: Nominal Levelized Flat Mid-Columbia Electric Price Forecast
Metric 2021-2040 Levelized Levelized
Deterministic $25.06 $26.10
Stochastic Mean $26.44 $27.86
10th Percentile $20.63 $21.69
50th Percentile $25.82 $27.12
95th Percentile $35.87 $37.93

Average 10th percentile Median 95th percentile Deterministic
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 179 of 259
Table 10.4: Annual Average Mid-Columbia Electric Prices ($/MWh)
Year Flat Off-Peak On-Peak Super Peak
2021 $19.67 $15.71 $22.64 $27.95
2022 $19.98 $16.28 $22.75 $28.61
2023 $20.44 $16.98 $23.05 $29.76
2024 $21.61 $18.28 $24.09 $31.54
2025 $22.76 $19.50 $25.19 $32.48
2026 $24.27 $21.43 $26.40 $34.67
2027 $23.57 $21.30 $25.27 $34.01
2028 $25.02 $23.35 $26.26 $36.73
2029 $25.92 $24.73 $26.80 $38.73
2030 $26.72 $26.25 $27.08 $41.52
2031 $29.46 $29.21 $29.66 $45.70
2032 $29.78 $29.54 $29.95 $47.17
2033 $31.22 $31.89 $30.74 $50.80
2034 $32.83 $34.06 $31.94 $54.50
2035 $33.66 $35.05 $32.64 $56.25
2036 $35.82 $37.16 $34.82 $60.63
2037 $36.12 $38.19 $34.58 $61.43
2038 $38.81 $40.76 $37.40 $66.43
2039 $38.60 $40.57 $37.13 $66.85
2040 $38.52 $40.84 $36.80 $69.79
2041 $39.09 $40.92 $37.74 $72.22
2042 $38.98 $40.31 $37.99 $73.58
2043 $40.24 $41.21 $39.51 $77.25
2044 $46.10 $47.15 $45.29 $86.30
2045 $43.94 $45.05 $43.11 $84.74
Traditionally on-peak prices are higher than off-peak prices. On-peak prices are typically 7 a.m. to 10 p.m. on weekdays plus Saturdays. This forecast shows off-peak prices outpacing on-peak prices on an annual basis beginning in 2033. This is due to the
increased quantities of solar generation placed on the system depressing on-peak prices. The first monthly flip between on- and off-peak begins in March 2026, and as more solar is added to the system, spreads to other shoulder months until it appears in all months, except for the winter season where solar production is lowest.

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

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 180 of 259
Figures 10.15 through 10.18 show the average prices for each hour of the season every 5 years of the price forecast. The spring and summer prices generally stay flat throughout
the 25 years as these periods have large quantities of hydro and solar generation to stabilize prices, but mid-day prices decrease over time and the other time periods increase. The winter and autumn prices will have large price increases due to less available solar energy to shift unless enough long-term storage is available. 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. Pricing for all resources will need to reflect these pricing curves so they can be properly valued against other resources.
Figure 10.16: Winter Average Hourly Electric Prices (December - February)

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2040 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 181 of 259
Figure 10.17: Spring Average Hourly Electric Prices (March - June)
Figure 10.18: Summer Average Hourly Electric Prices (July - September)

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2040 2045
2025 2030 2035
2040 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 182 of 259
Figure 10.19: Autumn Average Hourly Electric Prices (October - November)
Scenario Analysis
Electric market prices will have an impact on this resource plan due to how each resource option performs compared to other resources. This comparison uses market prices along with how each resource performs when customers need them (i.e. winter sustained peak).
As discussed earlier, market price forecasts can be computer processor and time
sensitive. However, understanding specific effects on the market place 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 following market scenarios were conducted:
• No Clean Energy Transformation Act (CETA) Scenario: This study identifies how the market place would differ absent the law passed in Washington State in
2019. This study assists calculating financial impacts of the change in energy policy. The major change in this scenario removes the social cost of carbon from resource choices for Washington State customers and removes the requirement of clean resources beyond those in the Energy Independence Act.
• Social Cost of Carbon Scenario: This scenario shows the implications of national carbon policy using the social cost of carbon as a “tax” on the entire electric system. In this scenario, power plants use this cost for dispatch decisions. This
scenario include a price of nearly $80 per metric ton in 2021 escalating to
approximately $100 in 2030, $155 in 2040, and $182 in 2045. No changes to load were included from any price elasticity effects of higher electric prices.
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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• Low Natural Gas Price Scenario: Prevailing low natural gas prices will have an impact on the resource selection because it will keep electric prices low. This scenario assumes prices in 2021 will be the same price in all future years, or in other words, no change in inflation. The results of this scenario demonstrate effects to both coal-fired facilities and the economics of renewable resources in a low
natural gas price environment.
• High Natural Gas Price Scenario: As opposed to the low natural gas price scenario, this scenario increases prices compared to the Expected Case using the
95th percentile of stochastic study. This equates to 23 percent higher prices in 2021, 50 percent higher prices in 2030, and 64 percent higher prices in 2045. This scenario should illustrate the price protection from non-natural gas-fired generation sources.
Scenario Electric Price Results Wholesale electric prices increase in all but the low natural gas price scenario. Figure 10.19 shows the nominal levelized prices for each scenario on a 20-year and 25-year basis compared to the Expected Case’s deterministic study. The “No CETA” scenario has
a modest 5 percent increase in prices due to less renewable generation in the system.
Including Social Cost of Carbon in the dispatch of wholesale generation increases prices by 75 percent. The Low Natural Gas Price scenario decreases the electric price forecast 30 percent. The Higher Natural Gas Price scenario increases electric prices by 39 percent. Figure 10.20 shows how the market prices materialize each year under the four
scenarios. All the scenarios, except the Social Cost of Carbon scenario, have linear price
forecasts. In the Social Cost of Carbon scenario, prices begin to fall because thermal generation costs rise until renewables dominate the market. In the High Natural Gas Price scenario, the end of the study bump in prices is due to increases in natural gas requirements due to the Columbia Generating Station assumed closure.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Figure 10.20: Mid-Columbia Nominal Levelized Prices Scenario Analysis

Figure 10.21: Mid-Columbia Annual Electric Price Scenario Analysis

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Scenario Generation Dispatch Results Each scenario has an effect on the type of generation constructed and dispatched in the
Western Interconnect. Figure 10.21 highlights generation dispatch in each scenario for 2040 and Table 10.5 shows the percent change in dispatch compared to the expected case. The biggest changes in dispatch for the Social Cost of Carbon scenario where the “tax” on coal and natural gas decreases their dispatch and increases wind generation. The natural gas price scenarios also operate as expected where high prices increase coal
generation and low prices decrease coal generation. Figure 10.22: 2040 Western Interconnect Generation Forecast
Table 10.5: Change in 2040 Regional Generation (Percent)
Scenario Coal Natural Gas Hydro Nuclear Wind Solar Other
The other major reason for the scenarios is to understand the impact of these futures to greenhouse gas emissions. Figure 10.22 shows scenario results on a levelized basis of emissions. This analysis assumes a 2.5 percent discount rate on the emissions to simplify
the comparison of the quantity of emissions between the scenarios and the Expected
Case. These analyses illustrates with the CETA policy reduces greenhouse gas emissions across the west by approximately two million metric tons per year, but only one
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million metric tons in the Northwest. Natural gas pricing has little effect on emissions in the northwest but affects other states more. The limitation in the northwest is due to low
natural gas usage in these states. The Social Cost of Carbon has the greatest impact by drastically reducing emissions across all areas. In all scenarios, the emissions levels are lower than historical 1990 emissions levels. Figure 10.23: 2021-2045 Levelized Greenhouse Gas Emissions

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11. Preferred Resource Strategy

In April 2019, Avista announced a corporate goal to provide 100 percent “carbon neutral”
energy by 2027 and by 2045 provide 100 percent clean energy, similar to the Washington
requirements under the Clean Energy Transformation Act (CETA) for 2030 and 2045
respectively. Avista must maintain system reliability at affordable rates when achieving
this goal. This will require renewable resources to remain cost competitive and for new
technologies to emerge. This chapter outlines how Avista plans to meet its future resource
needs including new CETA requirements and how we may achieve our own clean energy
goals, while keeping costs within acceptable levels as determined by the Idaho and
Washington utility commissions. Avista plans to acquire new resources by request for
proposals (RFPs) and opportunistic resource acquisitions to deliver reliable power supply
options to our customers at the lowest reasonable cost.

The IRP attempts to project the resource acquisition strategy using the best information
available at the time and our understanding of the potential requirements of Washington
State’s CETA. At the time of the drafting of this IRP, Washington had not released rules
regarding how power will be accounted for when meeting the 100 percent clean goal and
how the alternative compliance will work. Further, Avista did not include alternative
compliance options to meet CETA goals. Avista expects the next IRP (2021) will address
these rules when they are available. Avista’s Preferred Resource Strategy (PRS)
describes the lowest reasonable cost portfolio of resources given Avista’s need for new
capacity and clean energy resources, while taking into account social and economic
factors prescribed by state policies of where Avista serves customers. This analysis also
considers energy market risks, as alternative portfolios. The analysis tests sensitivities
Section Highlights
• Avista will seek 300 MW of wind energy to be online in 2022, or later, from both the Northwest and Montana.
• A combination of Montana wind and storage resources meet the 2026 capacity
deficits associated with the shutdown of Colstrip and the expiration of the
Lancaster contract.
• Wind resources are preferred over solar due to the potential to generate during periods of time when solar resources are not contributing to the grid, and the
desire to avoid resources whose timing is highly correlated with solar surplus
across the Western Interconnection.
• Avista must plan to meet future capacity needs in a flexible manner depending on what resources materialize from RFPs.
• requirements.
• Demand response programs will begin in 2025 ramping up to meet 100 MW of
peak demand by 2035.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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against the preferred portfolio to measure its cost changes to critical external factors like
higher or lower than expected levels of load growth.

The resource strategy includes both supply side resources and load management options
for customers including energy efficiency and demand response. The IRP measures
resource options against each other to find the lowest cost portfolio of resources to meet
resource deficits for winter and summer capacity, energy, and clean energy requirements.
Avista also explored ways to integrate distribution and transmission resource needs to
co-optimize all available options to serve its customers.
Resource Selection Process
Avista uses three models to evaluate resources for inclusion in the PRS. First is the
Aurora model, discussed in Chapter 10, which Avista uses to develop the electric price
forecast. The second model is Avista’s Reliability Assessment Model (ARAM), to test the
current resource portfolio’s reliability metrics and each resource option’s contribution to
overall portfolio reliability. Chapter 6 and Chapter 9 discuss these topics. The third model,
PRiSM (Preferred Resource Strategy Model), aids resource selection given the
information determined from the market price forecast and each resource’s reliability
characteristics. PRiSM evaluates each resource option’s costs (capital and operating),
capabilities, and operating margins compared to each other to determine the lowest cost
portfolio of resources to meet Avista resource needs (from Chapter 6). The model also
considers risk as evaluated by 500 different potential market futures.

PRiSM
Avista staff developed the first version of PRiSM in 2002 to support resource decision
making in the 2003 IRP. Ongoing enhancements improved the model since its initial
development. PRiSM uses a mixed integer programming routine to support complex decision making with multiple objectives. These tools provide optimal values for variables, given system constraints. The model uses an add-in function to Excel from Lindo Systems named What’s Best and the Gurobi solver. This software is the user interface to determine
which model inputs are variables and allows for the creation of constraints on the system. For example, Avista must simultaneously meet its clean energy standard in Washington and its projected winter capacity shortfall. The model solves using the net present value of resource costs given the following inputs:
1. Expected future deficiencies
o Summer Planning Margin from ARAM o Winter Planning Margin from ARAM o Annual energy o 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 o Operating margins
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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o Fixed operating costs 4. Supply-side resource, energy efficiency, and demand response options
o Fixed operating costs
o Return on capital o Interest expense o Taxes o Power Purchase Agreements
o Peak Contribution from ARAM
o Generation levels o Emission levels 5. Constraints o Must meet energy, capacity and clean energy shortfalls without market
reliance
o Resource quantities available to meet future deficits The Preferred Resource Strategy
To meet future customer load, Avista uses a combined strategy of acquiring energy
efficiency (reducing its customer’s energy consumption), working with customers to use
energy differently through demand response programs, upgrading our existing thermal
and hydroelectric generation fleet, contracting for new renewable energy resources, and
acquiring storage resources. Avista may take advantage of new opportunities, but will
seek the lowest cost and environmentally sustainable energy resources for our
customers. In addition, Avista may acquire resources other than those identified as
preferred due to actual pricing, lack of availability, the reliability benefits not materializing,
or the inability to meet state laws.

Avista’s resource strategy relies on available information at the time of this analysis and is subject to change based on how Avista expects customers to use energy in the future, how projected resource costs change, and on how market price conditions influence the
analysis and future acquisition. The strategy uses Avista’s interpretation of the new
Washington State CETA requirements. At the time of this IRP, rules are in development and Avista’s portfolio may change depending upon the methodology the Washington Commission uses to account for clean resources and alternative compliance.
Resource selections use economics, environmental objectives, and maintaining
customers reliably for decisions. Avista’s first resource adequacy shortfall occurs in January 2026, when Avista assumes Colstrip will not be available for purposes of this IRP and is no longer available to serve Washington customers due to Washington state law excluding the plant from customer rates. Although, it would be beneficial for Colstrip to
remain in operation through the 2025-2026 heating season for reliability unless new
capacity is under Avista’s control. Avista’s analysis of Colstrip in this IRP (Chapter 12) indicates retiring the plant for Idaho customers in 2025 rather than 2035 is the economic choice1. Avista cannot unilaterally close Colstrip units 3 and 4 under the ownership agreement. Avista’s energy needs increase later in 2026 when Avista’s contract with
1 Avista did not model any alternative shut down dates in this plan.
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Lancaster2 ends in October 2026. Filling these resource losses drives Avista’s need for additional capacity. Avista may have needs for additional renewable energy to meet
Washington State’s CETA. New renewable resource acquisitions will likely begin as early as 2022 to help with the transition to a cleaner resource portfolio. Avista may also acquire resources or contracts to minimize customer’s power costs. Avista’s resource plan is larger than in previous IRPs due to expected resource
retirements and new renewable energy requirements driven by the assumption Avista does not use Idaho’s share of the hydroelectric system to comply with CETA’s clean goals (except for the 20 percent alternative compliance). Avista’s interpretation of the law allows this energy to transfer between states with compensation to Idaho customers but awaits rulemaking before adjusting its resource plan.
The PRS divides the resource strategy between the first decade (2021-2030), second decade (2031-2040), and after 2040. Additional energy efficiency additions will occur over the 25-year plan. The next several sections of this chapter detail the expected resource acquisitions and summarize demand response and energy efficiency selections.
2021-2030 Supply Side Resource Selection
Avista will acquire new energy and capacity resources to meet clean energy goals and
capacity deficits in the next several years. Table 11.1 shows a complete list of new
generation selections. Avista’s first selection is 200 MW of wind energy divided between
Montana and the Northwest. Avista prioritized wind over other renewables due to its
energy delivery profile combined with PPA price forecasts. Actual acquisition quantities
and locations will be determined as part of RFPs and the transmission availability at the
time of the acquisition.

Under the IRP resource assumptions, the PRS includes wind due to generation in higher-
priced hours compared to solar and the potential for Montana wind projects to provide
peak capacity toward meeting customers’ winter peak load. In 2023, another 100 MW of
wind will help meet future clean energy targets. In total, Avista estimates 122 aMW of
clean energy procurement before 2023 to stay on track to meet the 80 percent CETA goal
by 2030. Avista may release an RFP in the second quarter of 2020 to solicit projects to
meet these goals. This RFP would be open to any clean resource with deliveries
beginning in 2022. While the IRP identifies online dates between 2022 and 2023, other
terms will receive consideration as long as the terms are in the best interests of Avista’s
customers and the resources meet the objectives of the CETA and Avista’s clean energy
goals.

2 Rathdrum Power, LLC, Combined Cycle Combustion Turbine.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 11.1: 2020 Preferred Resource Strategy (2021-2030)
Resource Time Period Conditions (MW) Winter Peak Capacity Capability (aMW)
On-system wind 2022 100 5 37
Montana wind 2022 100 40 48
On-system wind 2023 100 5 37
Kettle Falls modernization 2024 12 12 10 Rathdrum CT upgrade 2026 24 24 22
Long duration pumped hydro storage 2026 175 175 n/a
Post Falls modernization 2026 8 3.7 4.5
Montana wind 2027 200 80 96

Avista, like the other Washington utilities with an ownership share in Colstrip Units 3 and
4, is required to cease recovering the cost of coal-fired generation in Washington rates
after 2025. While the fate of the plant will depend on a decision made by all owners of the
facility, each of whom have their own economic circumstances, this IRP indicates Avista’s
most economic decision would be to close the plant at the end of 2025 as opposed to
20353. To replace the lost Colstrip capacity along with the expiring Lancaster PPA, Avista
seeks to add a combination of 175 MW of long duration pumped hydro and 200 MW of
Montana wind. Absent a resource addition that is dependable on cold winter days, the
ability to serve our customers is at great risk. Avista must acquire replacement generation
with operational characteristics that enable the Company to serve our customers when
they need it the most.

Avista is monitoring the potential for regional pumped hydro storage from several
proposed projects with varying sizes and durations. Avista has an interest in pursuing one
of these projects if the capacity and duration of the storage facility may help meet
customers’ winter peak load and if it exceeds the timing needs and pricing characteristics
of alternative resources. Avista’s analysis shows long duration storage assets may allow
it to replace the need for natural gas-fired peaking generation identified in the previous
IRP. Given the potential for storage, Avista considers it as part of its PRS and will actively
pursue storage as long as it meets the needs of our customers in a reliable and cost
effective manner. At any time, if Avista believes pumped storage is not feasible or cost
effective, Avista may pursue other alternatives including a natural gas-fired peaker. To
help with this decision making process, Avista may to issue a capacity RFP in 2021 to
identify and compare all potential alternatives.

3 From a regional reliability point of view, the plant would likely be better to close after the heating season ends in 2026. Avista expects this concern to be part of any closure decisions and should be a factor in policy decision making. Further, Avista did not model alternative closure dates in this IRP.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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The 200 MW Montana wind resource would serve customers by adding potentially low
cost clean energy as a contribution to meeting peak winter loads. This selection
anticipates the utilization of the existing transmission currently used by Colstrip and would
require this transmission capacity to be available. Any decision will likely result from an
RFP in 2022 or 2023 to identify potential projects in either Montana or other locations with
similar cost and operational attributes.

Existing Generation Project Upgrades
Avista is investigating the possibility of increasing the capacity of Kettle Falls by up to 12
MW by 2024. The Kettle Falls Generating Station is reaching the point where a
repowering effort may be justified in lieu of replacing equipment in-kind. Similar to Kettle
Falls, Avista will evaluate options to increase capacity at its Rathdrum CT site. Avista will
work with the manufacturer and other vendors to identify potential methods to increase
the capability of the plant. For planning purposes, this IRP estimates 24 MW of additional
capacity, but that number could vary depending on the full evaluation of alternatives.

The Post Falls hydroelectric facility will also undergo modernization, leading to capacity
improvements. At this point, the generating facilities are nearing the end of operating life,
and Avista will need to decide to modernize by either replacing the generators and
turbines with in-kind equipment or with equipment that increases the capacity of the
facility. The IRP calculates an incremental capacity improvement as part of the overall
modernization effort because it will increase the project’s capability and increase clean
energy production while utilizing the same renewable resource.

2031-2040 Supply Side Resource Selection
The second decade of the IRP’s resource selection strategy is a continued effort to
replace existing resource capacity, meet future load growth, and maintain resource
adequacy. The complete list of resource additions for this decade is in Table 11.2. The
first addition is a plan to replace the loss of our long-term regional hydro contracts with
new contracts. Avista anticipates the potential for 75 MW of existing hydroelectric capacity
to replace its expiring contracts. Existing hydroelectric generation will likely be competitive
given 2031 is in the midst of the 80 percent requirement of CETA. Although capacity
should be available, it will be a competitive process to acquire the generation.

The next resource selection is an upgrade or addition to the Long Lake Hydroelectric
Development. This IRP identifies a need for this additional capacity to assist in meeting
winter peak load and adding clean energy. Redevelopment of this project will require a
long lead-time. The first step in this redevelopment is to certify the project as complying
with the requirements of CETA. The need for this determination is due to language in
CETA section 4 prohibiting new diversions, new impoundments, new bypass reaches, or
expansion of existing reservoirs for qualifying resources. Avista believes an additional
project at Long Lake meets the intent of the law, but would need a declaratory order
before proceeding on the long permitting and construction process.
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Table 11.1: 2020 Preferred Resource Strategy (2031-2040)
Resource Time Period Conditions (MW) Winter Peak Capacity Capability (aMW)
Regional hydro PPA 2031 75 75 34
Long Lake upgrade/modernization 2035 68 68 23
Liquid air energy storage (LAES) 2036 25 15 n/a
Liquid air energy storage (LAES) 2038 25 15 n/a Liquid air energy storage (LAES) 2040 25 15 n/a

Assuming the Long Lake project is determined to qualify for CETA; Avista will need to
determine the best method to increase the capability at the project. Avista has identified
two alternatives requiring further study. The first alternative is a second powerhouse.
Avista has studied this alternative since the 1970s. The second alternative is to create a
new powerhouse with enough generating capability to retire the generating equipment in
the existing powerhouse. The advantage of this alternative is the existing generation
equipment is at the point it will require additional investment; this alternative could forgo
the need to make such an investment. Both alternatives would install a new penstock at
the location of the replacement for the saddle dam on the south end of the development.
When the preferred alternative is decided, Avista will proceed with the CETA qualification
review and the permitting process if warranted.

After 2035, Avista will require additional capacity to meet growing peak loads and the
likely retirement of the Northeast CT. This IRP anticipates storage resources will be the
economic choice in this period. At this time, using projected cost declines and required
duration requirements for resource adequacy, Liquid Air Energy Storage (LAES)
technology is the most likely option. Given the advancements in storage, the next 15
years of innovation may identify a lower cost option to meet customer needs. The
requirements identify additional LAES in 2036, 2038, 2040, and 2041. It is likely the
construction would be at one site with expansion capability as loads grow. Avista also
recognizes the closure of the Northeast CT for driving the resource need and an earlier
or later retirement of this resource will change the construction timetable for storage.

2041-2045 Supply Side Resource Selection
Avista typically does not forecast resource additions beyond 20 years. Given the CETA
requirement to be 100 percent non-emitting by 2045, Avista concluded that modeling
resources 25 years in the future had merit. The final five years of the plan, while relatively
uncertain, identifies the need to replace existing renewable PPAs, with the addition of
both renewable and storage technologies. Table 11.3 outlines these additions required to
meet both energy and capacity requirements of Avista’s customers.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 11.2: 2020 Preferred Resource Strategy (2041-2045)
Resource Time Period Conditions (MW) Winter Peak Capacity Capability (aMW)
Liquid air energy storage 2041 25 15 n/a
NW wind 2042 100 5 37
4 hour storage (lithium-ion) 2042 25 3.75 n/a
NW wind 2043 100 5 37 4 hour storage (lithium-ion) 2043 100 15 n/a
Solar 2043 5 0.1 1.3
Solar w/ storage (50 MW x 4 hours) 2044 50 8.5 12
4 hour storage (lithium-ion) 2044 75 11.25 n/a
NW wind 2045 100 5 37 4 hour storage (lithium-ion) 2045 100 15 n/a

Demand Response Selection
Demand Response (DR) will be an important part of Avista’s strategy to satisfy customer’s
peak load requirements as generating resources leave the portfolio. Currently, Avista
does not offer any load management programs, although it tested programs in the last
few years. To understand the potential for new programs, Avista contracted with Applied
Energy Group (AEG) to estimate the amount of DR available within the Idaho and
Washington service territories. This process identified 17 potential programs to reduce
187 MW of winter peak load. Some programs offer reduction in both winter and summer,
while others in only one season. Avista’s forecasted needs are for winter peak reduction
and several of the programs are cost effective. The first DR program selected in the PRS
begins in 2025 and is likely to ramp into full capability by 2029. Table 11.4 shows each of
the programs selected as part of the PRS and Figure 11.1 illustrates when DR enters the
system and how the penetration of DR programs increases.

DR programs to meet reliability targets will depend on the length of time the program can
reduce loads. For this IRP, Avista assumes a 60 percent peak credit. This is similar to the
amount of an equivalent capacity DR program compared to an equal size natural gas-
fired CT alternative. Due to the limited duration of the DR program, it only achieves 60
percent of the reliability benefits of a natural gas-fired CT. As Avista begins these DR
programs, experience and program design will determine the ultimate capacity
contribution to reliability. Further, the rate programs (time-of-use rates and variable peak
pricing) are not dispatchable and any actual benefit will come from observation of the
programs over time. DR programs may begin earlier than this IRP forecast as the 2021
Capacity RFP may highlight programs with cost effective potential prior to 2026. Certain
programs may have a long lead-time to recruit enough participants in order to have
sufficient DR capacity available.
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Table 11.3: PRS Demand Response Programs
Resource Start Year Maximum Load Reduction (MW)
Total 108.3

Figure 11.1: Demand Response

Energy Efficiency Selection
The final resource as part of the PRS is energy efficiency. This IRP studied over 6,000
energy efficiency programs to reduce demand and offset the need for new generation.
Avista models each of the programs individually to make sure to include each program’s
capacity and energy benefits in the analysis. This method allows for an accurate
accounting of peak savings for energy efficiency that would not be included with programs
modeled as buckets or compared to a levelized price of energy. In the midst of the IRP,
Washington passed legislation effectively changing certain programs to codes and
standards. This legislation reduces 2045 loads by six average megawatts from the more
stringent codes and standards and is included in the energy efficiency selection.
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As described in Chapter 3, the long-term energy and peak demand forecast already
includes the benefits of energy efficiency. This requires adjustments to the load forecast
to exclude the projected additions to energy efficiency so that potential specific programs
selection can occur. This adjustment uses an iterative process in the PRiSM model. The
process starts by adding back in the load represented by the prior 2017 IRP energy
efficiency amounts to the load forecast. PRiSM then solves to add both supply-side and
demand-side resources. The amount of selected energy efficiency changes as the
amount of new energy efficiency added to the load forecast. Then the process repeats
until the amount of energy efficiency selected and the amount of energy efficiency added
to the load forecast is similar. Table 11.5 shows these amounts added to the load forecast
and the ultimate amount of energy efficiency included in the PRS. The 187 aMW of
savings amount includes transmission and distribution losses along with the six aMW
from recent legislation for codes and standards. Avista expects total energy growth of 262
aMW between 2021 and 2045 with energy efficiency meeting 187 aMW. Energy efficiency
is the primary resource to meet increases in customer’s energy needs. Energy efficiency
meets 71 percent of new load growth compared to 53 percent in the 2017 IRP.

Table 11.4: Energy Efficiency Selected by PRiSM vs. Added to the Load Forecast
Year EE Added to the Load Forecast Selected EE from PRiSM

Over the course of the IRP planning horizon, 36 percent of new energy efficiency will
come from Idaho customers and 64 percent from Washington customers. A majority of
the savings will be from commercial customers (49 percent), followed by 41 percent from
residential customers. The remaining savings will be from industrial customers. The
greatest source of energy efficiency will come from lighting, and space and water heating.
Figure 11.2 shows the program’s share of the total savings to achieve the full 187.1 aMW
of savings. The energy efficiency programs not only lower annual energy demand, they
also reduce winter and summer peak demand. The selected programs lower winter peak
load growth by 120 percent of its annual energy and summer peak loads by 133 percent
of its annual average energy savings.

The amount of energy efficiency determined through this process will lead to program
creation in both Washington and Idaho. The IRP informs the energy efficiency team to
determine cost effective solutions and pursue new programs that may arise between IRP
analyses.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Figure 11.2: Energy Efficiency Savings Programs

Reliability Analysis
For the first time, this IRP includes a reliability analysis of the PRS. The increasing amount
of intermittent generation and storage included in the resource plan necessitated the need
for a reliability analysis. Prior plans used only planning margin criteria along with reliable
resource options to validate reliability. This plan uses a Loss of Load Probability Analysis
(LOLP) to validate its reliability for the year 2030. This analysis uses the ARAM model.
The model simulates 1,000 potential scenarios with different loads, wind estimates, hydro
conditions, and forced outage rates for each hour. This analysis also includes existing
resources expected to remain online in 2030 along with resource selections from this
plan.

The objective of this plan is to have a LOLP of near 5 percent. This means up to 5 percent
of the 1,000 simulations do not meet entire load requirements for the year. This
methodology is similar to the concept of one resource adequacy issue in 20 years. The
analysis compares this portfolio to alternative portfolios of existing resources with enough
added combustion turbines to have a 5 percent LOLP. This allows for a comparison of
reliability metrics compared to traditional resources and no resource additions. Table 11.6
shows this comparison. This analysis also assumes the ability to purchase short-term
market power. Such market power purchases are limited to 250 MW in high-load periods,
meaning temperatures below four degrees or above 84 degrees (daily average).
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Table 11.5: 2030 Reliability Metrics
Year Preferred Resource Natural Gas Resource
LOLP 5.3% 5.2% 54.3%
LOLH 2.02 hours 1.79 hours 50.8 hours
LOLE 0.18 0.14 3.71
EUE 330 MWh 264 MWh 10,092 MWh Total Events 196 156 4,047

Without any new resources, we would have a greater than 50 percent probability of not
being able to serve all loads in 2030. Both the PRS and 350 MW natural gas-fired
alternatives have nearly 5 percent probability of an event meeting the criteria for resource
adequacy. LOLP is the Northwest industry standard measurement of reliability, but other
measurements may be necessary to validate resource needs for the system, especially
as additional intermittent resources and storage enter the resource mix. The LOLP is
really a measure of the frequency of a bad year. Other metrics are frequency of an event
(LOLE)4, duration of an event (LOLH)5, and quantity of an event (EUE)6. It is possible
Avista will consider utilizing some of these metrics in the future to measure reliability.
Avista and other utilities are exploring regional resource adequacy targets and
accountability. If the region can agree on the development of a regional resource
adequacy program including the adoption of common reliability metrics and the ability to
share reserves, Avista could require fewer total capacity resources in the near term or
rely less on market purchases during extreme weather events.

Cost and Rate Projections
Avista typically only estimates costs related to existing and new resources as part of its
IRP analysis. Under CETA in Washington, Avista must estimate total electric revenue
requirements to determine if the cost of compliance exceeds CETA’s 2 percent cost
threshold over each of its four-year compliance periods beginning in 2030-2034.
Estimating non-power supply related cost is outside the scope of the IRP, so for this
calculation existing non-modelled costs inflate at 2 percent per year. This is the level of
inflation used throughout the modeling process.

With CETA, it is important to understand the change in utility cost due to the policy.
Specifically the provision to limit cost associated with its implementation, such as the 2
percent cost cap for meeting the 100 percent clean energy. This policy estimates rate
increases in four-year increments. Figure 11.3 shows the estimates for cost increases for
4 LOLE (Loss of Load Expectation) is defined by the total number of days within the 1,000 draws with unserved load dived by the number of draws (1,000).
5 LOLH (Loss of Load Hours) is the average duration of the event measured by the number of hours of the outages. 6 EUE (Expected Unserved Energy) is the average MWh of each event.
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Avista’s PRS in these increments. Over the 25-year period, costs are 1.4 percent higher
for the system to comply with CETA as compared to a portfolio without CETA
requirements. Avista found earlier investments in resources minimize the outer year cost
increases. As 2045 approaches, meeting 100 percent of Washington energy needs will
be difficult without new storage technology and the cost is likely to exceed the 2 percent
cost cap. Avista did not model the 2045 portfolio to serve 100 percent of energy or allow
the model to reach the 2 percent cost cap. Avista requires additional clarification and
guidance from Washington Commission rulemaking to model the cost cap correctly.

Figure 11.4 shows the forecast of annual power cost and average annual customer rates.
The figure separates costs into four categories. The first is non-power related costs,
estimated at $517 million7 or 65 percent of the total customer rate in 2021. These costs
include Fixed O&M related to Avista owned hydroelectric and biomass resources,
distribution, transmission, and administrative and general expenses. The remaining costs
are power supply related, including existing thermal generation, market transactions,
contracts, new generation, new transmission for new resources, and energy efficiency.
These cost categories are 1) the cost of existing generation and market transactions, 2)
the cost to add capacity to serve the highest load hours, and 3) the added cost to comply
with the CETA law in Washington. These added costs calculation compares the PRS to
alternative portfolios. The present value of future revenue requirement for the 25 years is
$11.8 billion. The existing resource cost and market transactions will contribute $3.7
billion to these estimates, while new capacity resource additions add $485 million, and
the CETA requirements add $163 million. These costs lead to increases in customer rates
of approximately 2 percent per year. Although power supply cost growth escalation is
higher than 2 percent, the effect on overall rates is low given the relatively small
contribution of power supply expense to the overall customer rate.

Figure 11.3: Percent Change in Revenue Requirement

7 This estimate does not forecast what Avista’s actual rates will be in 2021 and is an estimate for IRP analysis. This work does not include the level of scrutiny required for rate setting.
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Figure 11.4: Utility Revenue Requirement

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Schedule 1, Page 201 of 259
Environmental Analysis
Avista has a company-wide goal to serve all its customers with clean energy, specifically
100 percent of retail sales by net clean energy or emission offsets by 2027, and 100
percent of delivered energy by 2045. Avista is committed to this goal, and must balance
this goal with state policies, affordability and reliability. Affordability is key to Avista’s
customers, most of whom have lower than state median household incomes. In addition,
Avista customers live in areas subject to extreme winter and summer temperatures.
CETA’s cost cap provision reflects the need to balance the environmental and economic
attributes of energy.

Avista’s PRS meets 89 percent of the 2027 corporate goal, meaning nearly 90 percent of
energy delivered on average will be from clean resources including hydroelectric,
biomass, wind, and solar. Figure 11.15 shows the annual amounts. This estimate includes
(shown in blue) the clean energy associated with market purchases. A future with more
renewables and storage will require significant market interaction and regional
cooperation to deal with the oversupply of intermittent generation and resource adequacy.
As described in Chapter 10, the regional market will become cleaner as state laws require
higher amounts of clean energy, coal plants close, and natural gas prices stay low. Avista
estimates a portion of market transactions will be from clean resources. This estimate
from the net amount of energy Avista purchases or sells each year and then applies the
regional annual market emissions factor. With this factor, we can determine a split
between clean and thermal generation purchases.

Figure 11.5: Annual Clean Energy

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The PRS increases the amount of clean energy Avista serves to its customers and
reduces its greenhouse gas emissions. Avista can estimate the amount of emissions
associated with its owned generation based upon dispatch, but the amount of emissions
from some market purchases are difficult to estimate because the generation sources
cannot be determined, especially in power modelling. To estimate market purchase
emissions, Avista uses the annual average regional emissions rate. For example, when
Avista sells energy, the sales reduce Avista’s emissions using the associated market rate
or increase Avista’s emissions by market rates for purchases. The market used for this
analysis includes generation-related emissions from Washington, Idaho, Montana,
Oregon, Utah, and Wyoming8. Chapter 10 covers these emission rates in further detail.
For 2021, the greenhouse gas emissions rate is 672 pounds per MWh and by 2030, the
rate falls to 426 pounds per MWh. These emissions are in the total net emissions
calculation in Figure 11.6 in the dotted black line. These emissions also include
purchased power associated for storage resources. The orange bars represent the
expected emissions from current resources, while the yellow portion is from new
resources. The solid line shows the actual emissions from Avista plans in 2018 as a
comparison.

The 2030 emissions will be 79 percent lower than the 2018 levels and 85 percent lower
by 2045. The major emissions reductions come from the removal of Colstrip and
Lancaster from the system along with reductions in natural gas-fired dispatch. Another
point of interest is the regional change in emissions from electrification of the
transportation system. Avista’s current load forecast used in the PRS includes 100,000
vehicles converting from petroleum. This conversion reduces regional economy-wide
emissions and transfers vehicle charging onto the electric system, resulting in lower
emission rates. To illustrate this impact, the solid black line in Figure 11.6 shows the
reduction in vehicle emissions, which is greater than the total emission from Avista’s
power supply by 2045.

Another measure of emissions is emissions intensity. This is the net emissions from
Figure 11.6 divided by retail sales. For 2021, this is 461 pounds per MWh. By 2040, this
amount will decline to approximately 100 pounds per MWh. This data is in Figure 11.7.
As a comparison, Avista’s current emissions intensity as reported by the Washington
State Department of Commerce for Washington retail sales is 565 pounds per MWh.
8 Avista believes this footprint is beyond where Avista can acquire power from, but is consistent with methodologies currently used in Washington State fuel mix reporting. This may also change with rulemaking underway.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Figure 11.6: Greenhouse Gas Emissions
Figure 11.7: Total Net Greenhouse Gas Emissions Intensity

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Avista’s energy efficiency programs also reduce regional emissions and therefore an
estimate of the emissions avoided by energy efficiency needs to be calculated. There are
many methods to estimate the “avoided emissions” associated with energy efficiency, but
Avista chose to use the annual average market rate of emissions per MWh for this
calculation. The reason for this choice is the change in load requires a market response
of generation rather than just the individual utility; therefore, with less load, the utility and
the region will have lower emissions. Avista believes this method properly estimates the
change in emissions. For this analysis, each MWh of energy efficiency reduces regional
emissions by the market rate (Chapter 10- Figure 10.14). This reduction feeds into the
optimization of resources and the Washington State requirement to use the social cost of
carbon benefits of energy efficiency. The estimated savings are not included in Figure
11.6 above because of their inclusion in the net emissions to serve net load. The
calculation helps to understand the benefit of the emission reduction from energy
efficiency. Figure 11.8 shows the annual avoided greenhouse gas emissions from energy
efficiency. Over the 25-year forecast, Avista’s energy efficiency programs reduce regional
emissions by 3.25 million metric tons between 2021 and 2045.

Figure 11.8: Energy Efficiency GHG Emissions Savings

For resource optimization, this analysis includes the upstream emissions content from the
natural gas supply chain. Upstream emissions come from the drilling, processing, and
transportation of the natural gas to end use customers. Avista sources its natural gas for
power entirely from the Canadian system. As described in Chapter 9, the upstream
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emissions factor for our natural gas purchases is 0.784 percent including the associated
multipliers for methane release. These emissions are included in the optimization of
resource choices, but are not included in the estimate shown in Figure 11.7. Avista
estimates these emissions to be 10,000 metric tons in 2020 and 1,160 metric tons by
2045. Lower natural gas usage is the driver from lower upstream emissions.

Another metric to view Avista’s clean energy resource mix is to account for transfers of
clean energy between states (see Figure 11.9). The figure shows several different clean
energy measures to illustrate how energy serves customers in each state and as a
system. The dark blue line is “System Clean Generation (Clean Gen / Total Gen)” it
estimates the amount of clean generation as compared to Avista’s controlled generation,
this metric shows Avista’s system clean generation mix.

The light blue line “System Clean Sales (Clean Gen / Retail Sales)” shows the amount of
clean generation as compared to annual system retail sales. Any remaining power to
serve customers is from market transactions or from other generation. The dotted blue
line estimates the amount of net market transactions and is labeled “Unspecified Market
Transactions (Total / System Load).” Clean energy assigned to Washington for CETA
compliance is the green line “WA Assigned Clean (Clean Gen / Retail Sales)” and the
remaining clean energy for Idaho is the orange line “ID Assigned Clean (Clean Gen /
Retail Sales).” Lastly, this chart does not forecast any REC sales to non-Avista
customers.

Figure 11.9: Clean Energy Mix Forecast

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Avoided Cost
As part of the IRP process, Avista calculates the avoided or incremental cost to serve
customers by comparing the PRS cost to alternative portfolios. There are two important
avoided cost calculations: the first is for new generation resources and the second is for
energy efficiency.

New Resource Avoided Cost
The 2020 IRP’s avoided costs are in Table 11.6. However, avoided costs will change as
Avista’s loads and resources change, as well as with changes in the wholesale power marketplace. Avoided Costs use the best available estimate at the time of the analysis with the data available. Any precise or specific project characteristics will likely change the value of a resource. The prices shown in the table represent energy and capacity values for different periods and product types, including renewable energy projects. For
example, a new generation project with equal deliveries over the year in all hours has an energy value equal to the flat energy price shown in Table 11.6. The table also includes traditional on-peak and off-peak pricing as a comparison to the flat price. In addition to the energy prices, this theoretical resource would also receive the capacity value as it
produces power at the time of system peak. This system peak contributing value begins
in 2026 for resources that can dependably meet winter peak requirements. Capacity value is the resulting marginal cost of capacity each year. Specifically, the calculation compares a higher cost of a portfolio with new capacity against a lower cost
portfolio with no new resources for each year. Avista uses these annual cash flow
differences to create an annualized cost of capacity beginning the first year the utility is short with an annual price adjustment of 2 percent per year. This calculation removes the variability in annual payments but is the same present value cost. The next step divides the cost by the amount of added capacity in terms of 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. To obtain a full capacity payment, the resource must generate 100 percent of its capacity rating at the time of system peak. For example, solar receives a 2 percent credit based
on ELCC analysis and would receive 2 percent of the capacity payment as compared to
its operational capacity. For wind resources, their location determines the capacity credit they receive. Northwest wind contributes 5 percent of its operational capacity to winter peaks, while Montana wind contributes 40 percent. No matter the resource, Avista will need to conduct an ELCC analysis for any specific project it evaluates to determine its
peak credit. Another item to consider for intermittent resources is the cost to integrate the
variability onto the system. Any potential resource seeking Avoided Cost pricing shall reduce its compensation by these integration costs. The clean energy premium calculation is similar to the capacity credit, but in this instance,
it estimates the cost to comply with CETA by comparing the PRS to a portfolio without
complying with CETA. Chapter 12 discusses these portfolios. Avista uses these annual cash flow differences to create an annualized cost of capacity beginning with the first year of clean energy acquisition with an annual price adjustment of 2 percent per year. Then
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 207 of 259
the new annual cost divided by the incremental megawatt hours of generation. This value shows the amount of extra cost per MWh to meet CETA9. This benefit includes the cost
associated with changing to cleaner capacity resources but also adding clean energy resources. A scenario is also included to highlight the Clean Premium for projects if federal tax credits continue (see Table 11.7). In this scenario, the incremental cost of clean energy is lower
due to the cost shift from utility customers to tax payers. The clean premium estimate for specific future projects will depend on the amount of clean energy and clean capacity the asset produces. Avista believes the best method for estimating avoided costs of new clean energy
resources is through the RFP process. An RFP process provides real cost information with specific energy resources. These pricing results are the real avoided costs if Avista were to acquire additional clean energy resources. For capacity resources, an RFP is also the best method for determining these costs. Although certain cases, specifically acquiring hydroelectric existing resources may not be available in an RFP process, and
Avista must use judgement and market intelligence when acquiring these resources to ensure they are at competitive prices.
Energy Efficiency Avoided Cost
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 above, but differs in the case of energy efficiency. In this
scenario, the model disables the option to use energy efficiency as a resource. This
method results in the total benefit energy efficiency brings to the system.

Unlike generation resources, the energy efficiency avoided costs include additional
premium components. First is the 10 percent NPCC preference adder. Second is the
consideration of transmission and distribution losses. Third is savings of constructing less
transmission and distribution facilities. The social cost of carbon is also included for
project evaluation in Washington. For this example, the social cost of carbon applies to
the projected greenhouse gas savings from the market transactions as described above.
For avoided cost purposes, this consideration is included in the clean energy premium.
In summary, energy efficiency avoided cost is the first value of the saved energy. The
second is the savings in capacity resources as defined by the difference between a
portfolio meeting only capacity requirements and no capacity obligations. Third, is the
incremental cost to meet the clean energy requirements of CETA. This includes the value
9 Avista is modeling the CETA premium as an energy payment for Avoided Cost. Analysis shows the CETA premium actually changes some capacity decisions and theoretically, some of the clean energy premium should be associated with capacity for clean energy resources. This also assume Idaho’s share of the hydroelectric system does not contribute to Washington’s 100 percent goals, with the exception of alternative compliance limited to 20 percent in 2030.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 208 of 259
of less clean energy resources required by energy efficiency effect of lowering load and
the reduction in greenhouse emissions. Figure 11.9 shows each of these cost estimates
below.
Table 11.6: New Resource Avoided Costs
Year Energy Flat On-Peak Off-Peak Premium Capacity
2021 19.67 22.64 15.71 0.00 0.0
2022 19.98 22.75 16.28 11.75 0.0
2023 20.44 23.05 16.98 11.99 0.0
2024 21.61 24.09 18.28 12.23 0.0
2025 22.76 25.19 19.50 12.47 0.0
2026 24.27 26.40 21.43 12.72 107.7 2027 23.57 25.27 21.30 12.97 109.9
2028 25.02 26.26 23.35 13.23 112.1
2029 25.92 26.80 24.73 13.50 114.3
2030 26.72 27.08 26.25 13.77 116.6
2031 29.46 29.66 29.21 14.04 118.9
2032 29.78 29.95 29.54 14.32 121.3 2033 31.22 30.74 31.89 14.61 123.7
2034 32.83 31.94 34.06 14.90 126.2
2035 33.66 32.64 35.05 15.20 128.7
2036 35.82 34.82 37.16 15.51 131.3
2037 36.12 34.58 38.19 15.82 133.9
2038 38.81 37.40 40.76 16.13 136.6
2039 38.60 37.13 40.57 16.45 139.3
2040 38.52 36.80 40.84 16.78 142.1
2041 39.09 37.74 40.92 17.12 145.0
2042 38.98 37.99 40.31 17.46 147.9
2043 40.24 39.51 41.21 17.81 150.8 2044 46.10 45.29 47.15 18.17 153.9
2045 43.94 43.11 45.05 18.53 156.9
15 yr Levelized 24.58 26.11 22.55 11.81 64.8
20 yr Levelized 26.44 27.55 24.98 12.43 75.1
25 yr Levelized 27.86 28.77 26.66 12.93 82.2

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 209 of 259
Table 11.7: New Resource Avoided Costs With Renewable Tax Credits
Year
Energy Flat Energy On-Peak Energy Off-Peak
Premium (w/ Tax Incentive) Capacity
2021 19.67 22.64 15.71 0.00 0.0
2022 19.98 22.75 16.28 3.44 0.0
2023 20.44 23.05 16.98 3.50 0.0
2024 21.61 24.09 18.28 3.57 0.0
2025 22.76 25.19 19.50 3.65 0.0
2026 24.27 26.40 21.43 3.72 107.7
2027 23.57 25.27 21.30 3.79 109.9
2028 25.02 26.26 23.35 3.87 112.1
2029 25.92 26.80 24.73 3.95 114.3
2030 26.72 27.08 26.25 4.03 116.6 2031 29.46 29.66 29.21 4.11 118.9
2032 29.78 29.95 29.54 4.19 121.3
2033 31.22 30.74 31.89 4.27 123.7
2034 32.83 31.94 34.06 4.36 126.2
2035 33.66 32.64 35.05 4.44 128.7
2036 35.82 34.82 37.16 4.53 131.3
2037 36.12 34.58 38.19 4.62 133.9
2038 38.81 37.40 40.76 4.72 136.6
2039 38.60 37.13 40.57 4.81 139.3
2040 38.52 36.80 40.84 4.91 142.1
2041 39.09 37.74 40.92 5.01 145.0 2042 38.98 37.99 40.31 5.11 147.9
2043 40.24 39.51 41.21 5.21 150.8
2044 46.10 45.29 47.15 5.31 153.9
2045 43.94 43.11 45.05 5.42 156.9
15 yr Levelized 24.58 26.11 22.55 3.45 64.8
20 yr Levelized 26.44 27.55 24.98 3.63 75.1 25 yr Levelized 27.86 28.77 26.66 3.78 82.2

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 210 of 259
Figure 11.10: Avoided Cost of Energy Efficiency

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12. Portfolio Scenario Analysis

The Preferred Resource Strategy (PRS) is Avista’s 25-year strategy to meet future loads and replace generation resources. Because the future is often different from the IRP forecast, the strategy needs to be flexible to serve customers under a range of plausible outcomes. This IRP identifies many permutations of potential resource strategies due to
availability and pricing. Further, 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 2020 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, how will our resource strategy change if pumped storage or Long Lake 2 is not an economically viable resource alternative, or if the Lancaster PPA extends beyond
2026? This chapter covers potential alternative portfolios including different Colstrip
shutdown dates, higher and lower load forecasts, tax credit scenarios, and the costs of implementing the 100 percent clean energy corporate goal. Figure 12.1 shows how resource decisions may change depending on future events and how resource decisions may interact with each other.

In addition to alternative portfolio choices, Avista also tested the portfolios with alternative market futures. These scenarios show how the portfolios fare against each other with a carbon tax, if natural gas prices were higher or lower, or if the costs of complying with CETA in Washington were removed. In addition to these market scenarios, this chapter
shows how the portfolios perform when considering the 500 iterations of market futures, which portfolios have lower risk, and what is the cost to reduce risk. Lastly, this chapter covers a scenario where a major shift to electrification from fossil fuels begins. In this scenario, space and water heating begins to shift to electric rather than natural gas,
transportation electrifies, and additional homes well beyond the current rate of adoption
install rooftop solar panels. This scenario outlines the grid impacts, costs, and environmental impacts of as an electrification policy.
• Colstrip is more economically retired at the end of the 2025/26 heating season
as compared to 2035.
• The PRS, compared to a portfolio without CETA, includes an implied carbon price of $55 per metric ton.
• Electrifying the space and water heating system exceeds the social cost of
carbon.
• Electrifying the transportation system leads to significant regional emissions- but will increase utility emissions.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 212 of 259
Figure 12.1: Resource Acquisition Roadmap

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Portfolio Scenarios
Avista studied 15 alternative portfolios to compare cost, risk, and emissions to the PRS. 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
Montana wind 2022 100 NW wind 2022-2023 200 Kettle Falls upgrade 2026 12 Colstrip 3 & 4 exits portfolio 2026 -222 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 175 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8 Montana wind 2027 200 Mid-Columbia hydro 2031 75 Northeast CTs retires 2035 -55 Long Lake 2nd powerhouse 2035 68 Liquid-air storage (16 hours) 2036-2041 100
Wind (including PPA renewals) 2041-2043 300
Lithium-ion storage (4 hour) 2042-2045 300 Solar w/ storage (4 hours) 2044 55 4-hr Storage for Solar 2044 50 Supply-side resource net total (MW) 1,133 Supply-side additions through 2045 (MW) 1,667 Demand Response through 2045 (MW) 112 Energy Efficiency through 2045 (aMW) 187

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Portfolio #2: Least Cost Plan- without CETA This portfolio has many objectives. First, to understand how the utility would plan its
portfolio prior to CETA’s inception in Washington. It allows Avista to identify the incremental cost of CETA and develop the 2 percent rate cap analysis within CETA. It is used for avoided cost calculations of clean energy and could potentially be used to identify resource cost allocation for resources acquired for one of Avista’s two states it serves. The specific resource selection for this portfolio is in Table 12.1. The major differences
between this portfolio and the PRS are this portfolio includes fewer new wind resources, the inclusion of natural gas CTs, and no Long Lake 2. Table 12.2: Portfolio #2- Least Cost Plan- without CETA
Montana wind 2022 100 Kettle Falls upgrade 2026 12
Colstrip 3 & 4 exits portfolio 2026 -222
Rathdrum CT 1 & 2 upgrades 2026 24
Long-duration pumped hydro 2026 200 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8 Natural Gas CT 2027 92 Mid-Columbia hydro 2031 75 Northeast CTs retires 2035 -55 Liquid-air storage (16 hours) 2038 25 Lithium-ion storage (4 hours) 2039 25 Liquid-air storage (16 hours) 2040-42 75 Natural gas CT 2043 55 Lithium-ion storage (4 hour) 2045 53 Supply-side resource net total (MW) 210
Supply-side additions through 2045 (MW) 744 Demand Response through 2045 (MW) 87 Energy Efficiency through 2045 (aMW) 166

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Portfolio #3: Clean Energy Plan (CEP) This portfolio identifies the resource acquisition steps and cost implications with Avista
achieving 100 percent net clean energy by 2027 for all customers. This portfolio does not attempt to serve 100 percent of load every hour of the year with non-fossil fuels or purchase Renewable Energy Credits. This portfolio requires additional resources to serve Idaho retail sales with clean energy. This assumption would eliminate Idaho’s ability to sell its clean energy attributes to either Avista’s Washington customers or other utilities. Table 12.3: Portfolio #3- Clean Energy Plan
Montana wind 2022 100 NW solar 2022 150 NW wind 2023 200 Kettle Falls upgrade 2024 12 Colstrip 3 & 4 exits portfolio 2026 -222 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 125 Lancaster PPA expires 2026 -257 Montana wind 2026 200 Post Falls upgrade 2027 8
NW Solar 2027-2030 325
Geothermal 2029 20
Mid-Columbia hydro 2031 75 Long Lake 2nd powerhouse 2031 68 Northeast CTs retires 2035 -55 Solar w/ 150 MW storage (4 hours) 2033-2040 195 Wind (including PPA renewals) 2041-2043 300 Liquid-air storage (16 hours) 2042 25 Lithium-ion storage (4 hours) 2043-2045 225 Solar w/ storage 2040-2045 70 Storage for solar (4 hours) 2045 50 Supply-side resource net total (MW) 1,638 Supply-side additions through 2045 (MW) 2,172 Demand Response through 2045 (MW) 111
Energy Efficiency through 2045 (aMW) 213
Avista conducted a state specific study with this scenario where it compares the allocated
cost to Idaho compared to the PRS. In this case, the Idaho customers pay only the
allocated cost from Portfolio #2, and Washington customers pay all incremental costs from the PRS. Idaho would not sell its excess RECs to Washington or any other buyer in this scenario. This rate comparison shown in Figure 12.2 is for three REC price scenarios. The first scenario is RECs remain at $4 per MWh for the whole period. REC prices are
$6.40 in the second scenario, and REC prices increase to $15.40 per MWh in the high
price scenario. This analysis shows Idaho rates will increase approximately 5 percent until 2027 and between 12 and 20 percent higher between 2030 and 2035 due to the clean energy goal.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 216 of 259
Figure 12.2: Idaho Clean Energy Plan Rate Impacts
Portfolio #4: Rely on Energy Market Only This portfolio estimates the cost to serve only the energy portion of power supply, allowing
for the calculation of the cost of capacity. Further, this portfolio shows what resource
additions are cost effective based on energy alone. The results show the Post Falls hydroelectric upgrade and 127 aMW of energy efficiency are the lowest cost resource alternatives. Table 12.4: Portfolio #4- Clean Energy Plan
Colstrip 3 & 4 exits portfolio 2026 -222 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8 Northeast CTs retires 2035 -55 Supply-side resource net total (MW) -526 Supply-side additions through 2045 (MW) 8 Demand Response through 2045 (MW) 0 Energy Efficiency through 2045 (aMW) 127

Low REC Prices Mid-Range REC Prices High REC Prices
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 217 of 259
Portfolio #5: 100 Percent Net Clean and No CTs by 2045 This portfolio attempts to estimate costs to serve the capacity in addition to energy with
all clean resources. Avista has not conducted a reliability analysis of this portfolio to determine if it satisfies the 5 percent LOLP requirement although uses the same planning margin target as the PRS. The model increases both renewables and storage along with “clean” baseload resources from geothermal, biomass, and nuclear. The model may select additional hydroelectric upgrades, such as the Monroe Street upgrade, as well if
available. Table 12.5: Portfolio #5- CEP and No CTs by 2045
NW solar 2022 150 MT wind 2022 100 NW wind 2023 200 Kettle Falls upgrade 2024 12 Colstrip 3 & 4 exits portfolio 2026 -222 Long duration pumped hydro 2026 150 MT wind 2026 200 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8 NW solar 2027-2030 325 Geothermal 2029 20 Mid-Columbia hydro 2031 75 Long Lake 2nd powerhouse 2031 68
NW solar 2033 55 Northeast CTs retires 2035 -55 NW solar w/ storage 2036-2040 140 Storage for solar (4 hours) 2036-2040 125 Liquid air storage (16 hours) 2040 200 Pumped hydro 2040 75 Rathdrum CTs removed 2040 -154 Wind (including PPA renewals) 2041-2043 300 Kettle Falls CT removed 2043 -9 Boulder Park removed 2043 -25 Liquid air storage (16 hours) 2042-2044 125 Lithium-ion storage (4 hours) 2043-2045 28 Coyote Springs 2 removed 2045 -302
NW solar w/ storage 2044-2045 130
Storage for solar (4 hours) 2044-2045 75
Pumped hydro 2045 225 Small nuclear 2045 100 Biomass 2045 50 Supply-side resource net total (MW) 1,912 Supply-side additions through 2045 (MW) 2,936 Demand Response through 2045 (MW) 108 Energy Efficiency through 2045 (aMW) 214
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 218 of 259
Portfolio #6: Least Cost Plan w/o Pumped Hydro or Long Lake Upgrade The PRS includes some level of risk of two major resources not being able to be either
constructed when needed or even able to be constructed at all due to licensing constraints. This portfolio estimates Avista’s resource plan if long duration pumped hydro1 or the Long Lake upgrade are not available due to any reason, the net result of these changes is a need for 245 MW of natural gas-fired CTs and shifting 200 MW of Montana wind to 2035 to coincide with the retirement of the Northeast CT. Table 12.6: Portfolio #6- LC without Pumped Hydro or Long Lake Upgrade
Montana wind 2022 100 NW wind 2022-2023 200 Kettle Falls upgrade 2026 12 Colstrip 3 & 4 exits portfolio 2026 -222 Rathdrum CT 1 & 2 upgrades 2026 24 Natural Gas CT 2027 245 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8 Mid-Columbia hydro 2031 75 Northeast CTs retires 2035 -55
Montana wind 2035 200
Liquid-air storage (16 hours) 2038-2041 75
Wind (including PPA renewals) 2041-2043 300 Lithium-ion storage (4 hour) 2044-2045 150 Liquid-air storage (16 hours) 2043 25 Solar w/ storage 2045 100 Storage for solar (4 hours) 2045 100 Geothermal 2045 20 Supply-side resource net total (MW) 1,100 Supply-side additions through 2045 (MW) 1,634 Demand Response through 2045 (MW) 108 Energy Efficiency through 2045 (aMW) 177

1 Excludes the 40 and 80-hour options, but allows PRiSM to select 8. 16, and 24-hour projects if cost effective.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 219 of 259
Portfolio #7: Least Cost Plan with Colstrip extended to 2035, without CETA If shutdown dates for Colstrip Units 3 and 4 occur in 2035, Avista’s strategy would change
due to the 200 MW of Montana wind not being available because of limited transmission capacity. The plan would require nearly the same amount of pumped hydro as Portfolio #1 and would require 92 MW of natural gas-fired CTs. This scenario requires fewer renewable resources since it does not include CETA. This portfolio helps illustrate the change in portfolio cost with and without Colstrip due to Washington’s CETA. This
portfolio also provides details comparing a 2025 versus a 2035 Colstrip exit. Table 12.7: Least Cost Plan with Colstrip extended to 2035, without CETA
Montana wind 2022 100 Kettle Falls upgrade 2026 12 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 200 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8 Natural Gas CT 2027 92 Mid-Columbia hydro 2031 75 Colstrip 3 & 4 exits portfolio 2035 -222 Northeast CTs retires 2035 -55 Natural Gas CT 2035 84 Liquid-air storage (16 hours) 2038-42 100 Lithium-ion storage (4 hours) 2039 25
Natural gas CT 2043 55 Lithium-ion storage (4 hour) 2045 53 Supply-side resource net total (MW) 294 Supply-side additions through 2045 (MW) 828 Demand Response through 2045 (MW) 88 Energy Efficiency through 2045 (aMW) 166

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 220 of 259
Portfolio #8: Least Cost Plan with Colstrip extended to 2035, with CETA Portfolio #8 includes CETA assumptions, but moves Colstrip’s proposed shutdown date
to 2035. This portfolio helps identify whether or not Colstrip is cost effective to continue operating on a system basis to serve load outside of Washington. Portfolio #8 requires additional pumped hydro storage, selects no natural gas-fired CTs, and Montana wind shifts out until after Colstrip exits the portfolio in 2035. Table 12.8: Least Cost Plan with Colstrip extended to 2035, with CETA
Montana wind 2022 100 NW wind 2022 100 NW wind 2023 100 Kettle Falls upgrade 2024 12 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 250 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8
Mid-Columbia hydro 2031 75 Northeast CTs retires 2035 -55 Long Lake 2nd powerhouse 2035 68 Colstrip 3 & 4 exits portfolio 2036 -222 MT wind 2036 200 Wind (including PPA renewals) 2042-2045 300 Liquid-air storage (16 hours) 2043 25 Solar w/ storage 2044 50 Storage for solar (4 hours) 2044 50 Lithium-ion storage (4 hour) 2045 175 Supply-side resource net total (MW) 1,003 Supply-side additions through 2045 (MW) 1,537
Demand Response through 2045 (MW) 112 Energy Efficiency through 2045 (aMW) 182

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 221 of 259
Portfolio #9: Least Cost Plan with 30 percent Higher Pumped Hydro Storage Costs One of the risks of the PRS is the estimated costs of the long duration pumped hydro
storage could be significantly higher than estimates used in the PRS. This portfolio’s objective is to identify the breaking point. At 30 percent higher PPA costs, the model begins to shift pumped hydro to natural gas-fired CTs. Table 12.9 identifies these changes along with others. Table 12.9: Least Cost Plan with 30 Percent Higher Pumped Hydro Storage Costs
Montana wind 2022 100 NW wind 2022 100 NW wind 2023 100 Kettle Falls upgrade 2024 12 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 75 Colstrip 3 & 4 exits portfolio 2026 -222 Lancaster PPA expires 2026 -257
Natural gas CT 2027 92 Post Falls upgrade 2027 8 MT Wind 2027 200 Mid-Columbia hydro 2031 75 Northeast CTs retires 2035 -55 Long Lake 2nd powerhouse 2035 68 Liquid-air storage (16 hours) 2036-41 100 Wind (including PPA renewals) 2042-2045 300 Lithium-ion storage (4 hour) 2042-2045 303 Solar w/ storage 2044 50 Storage for solar (4 hours) 2044 50 Supply-side resource net total (MW) 1,123
Supply-side additions through 2045 (MW) 1,657 Demand Response through 2045 (MW) 111 Energy Efficiency through 2045 (aMW) 189

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 222 of 259
Portfolio #10: Least Cost Plan with Federal Tax Credit Extension One of the challenges with high renewable penetration rates is the added costs of
renewables above market prices. There are scenarios where the Federal government could extend the Wind PTC and Solar ITC. This portfolio identifies the changes in resource selection and changes in cost of this scenario. This scenario also identifies how avoided costs would change with a tax credit extension. Table 12.10: Least Cost Plan with Federal Tax Credits Extension
Montana wind 2022 100 NW wind 2023 200 Kettle Falls upgrade 2024 12 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 175 Colstrip 3 & 4 exits portfolio 2026 -222 Lancaster PPA expires 2026 -257 Post Falls upgrade 2027 8
MT Wind 2026 200 Mid-Columbia hydro 2031 75 Northeast CTs retires 2035 -55 Natural gas CT 2035 92 Liquid-air storage (16 hours) 2038-2043 100 Wind (including PPA renewals) 2042-2045 300 Lithium-ion storage (4 hour) 2043-2045 100 Solar w/ storage 2044-2045 150 Storage for solar (4 hours) 2044-2045 150 Supply-side resource net total (MW) 1,152 Supply-side additions through 2045 (MW) 1,686 Demand Response through 2045 (MW) 108
Energy Efficiency through 2045 (aMW) 181

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 223 of 259
Portfolio #11: Clean Resource Plan with Federal Tax Credits Extension This scenario is similar to Portfolio #10, but this case meets Avista’s Clean Energy
Strategy’s (similar to Portfolio #2) added renewable objective. This allows the addition of new resources at a lower cost with the tax credit while identifying cost increases necessary to move toward 100 percent clean energy when compared to the least cost strategy. This portfolio requires additional solar and storage resources toward the end of the plan.
Table 12.11: Least Cost Plan with Federal Tax Credits Extension
Montana wind 2022 100 NW solar 2022 150 NW wind 2023 200 Kettle Falls upgrade 2024 12 Colstrip 3 & 4 exits portfolio 2026 -222 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 125 Lancaster PPA expires 2026 -257 Montana wind 2026 200 Post Falls upgrade 2027 8
NW Solar 2027-2031 350
Geothermal 2029 20
Mid-Columbia hydro 2031 75 Long Lake 2nd powerhouse 2031 68 Northeast CTs retires 2035 -55 Solar w/ storage 2033-2040 225 Storage for solar (4 hours) 2033-2040 225 Wind (including PPA renewals) 2041-2043 300 Lithium-ion storage (4 hours) 2042-2045 225 Liquid-air storage (16 hours) 2043 25 Solar w/ storage 2044-2045 75 Storage for solar (4 hours) 2044-2045 75 Supply-side resource net total (MW) 1,948 Supply-side additions through 2045 (MW) 2,482
Demand Response through 2045 (MW) 111 Energy Efficiency through 2045 (aMW) 203

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 224 of 259
Portfolio #12: Least Cost Plan with Low Economic Growth Lower economic growth in the service territory may lead to flat load growth for Avista.
This scenario estimates average energy will be approximately 89 aMW less than the PRS by 2045 and winter peak loads will be 136 MW less by 2045. Effectively, loads will be flat across the 25-year forecast in this scenario. Additional information regarding these low and high economic growth scenarios is included in Chapter 3. These load changes result in less generation required to meet load. Another item to note in this scenario is with lower
growth, the amount of energy efficiency is likely to be overstated. Avista did not modify the Energy Efficiency potential study or ramp rates for this scenario. Table 12.12: Low Economic Growth
Montana wind 2022 100 NW wind 2022 100
Kettle Falls upgrade 2024 12
Colstrip 3 & 4 exits portfolio 2026 -222
Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 100 Lancaster PPA expires 2026 -257 Montana wind 2027 200 Post Falls upgrade 2027 8 Mid-Columbia hydro 2031 75 Long Lake 2nd powerhouse 2031 68 Northeast CTs retires 2035 -55 Wind (including PPA renewals) 2042-2045 300 Lithium-ion storage (4 hours) 2041-2045 225 NW solar 2045 10 Supply-side resource net total (MW) 688
Supply-side additions through 2045 (MW) 1,222 Demand Response through 2045 (MW) 108 Energy Efficiency through 2045 (aMW) 180

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 225 of 259
Portfolio #13: Least Cost Plan with High Economic Growth Higher economic growth in the service territory leads to higher load growth for Avista.
This scenario estimates average energy will be approximately 96 aMW more than the PRS by 2045 and winter peak loads will be 152 MW higher by 2045. Additional information regarding this load scenario is included in Chapter 3. These load changes result in more generation required to meet load. Another item to note in this scenario is with higher growth, the amount of energy efficiency is likely to be understated. Avista did not modify
the Energy Efficiency potential study or ramp rates for this scenario. Table 12.13: High Economic Growth
Montana wind 2022 100 NW wind 2022 100 NW wind 2023 100 Kettle Falls upgrade 2024 12 Colstrip 3 & 4 exits portfolio 2026 -222 Rathdrum CT 1 & 2 upgrades 2026 24 Long-duration pumped hydro 2026 250 Lancaster PPA expires 2026 -257 Montana wind 2027 200 Post Falls upgrade 2027 8 Mid-Columbia hydro 2031 75 Natural gas CT 2033 48 Long Lake 2nd powerhouse 2035 68
Northeast CTs retires 2035 -55 Natural gas CT 2037 48 Liquid air storage (16 hours) 2040-2043 100 Wind (including PPA renewals) 2041-2043 300 Solar w/ storage 2041-2045 205 Storage for solar (4 hours) 2041-2045 200 Lithium-ion storage (4 hours) 2043-2044 200 Geothermal 2045 20 Supply-side resource net total (MW) 1,524 Supply-side additions through 2045 (MW) 2,058 Demand Response through 2045 (MW) 112 Energy Efficiency through 2045 (aMW) 181

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 226 of 259
Portfolio #14: Least Cost Plan with Lancaster Extended Five Years The Lancaster PPA expires in October 2026. The plant has not reached the end of its
useful life and theoretically, the plant owner and Avista could agree to a PPA extension or another alternative such as a purchase and sale agreement. This scenario studies how the Avista portfolio may change with a five-year extension. Avista’s interpretation of CETA would allow this extension since the plant currently meets the Washington emission performance standard and does not preclude Avista from meeting either of the clean
energy objectives. The results of this portfolio removes the need of the long duration pumped hydro storage project but replaces it with a new natural gas-fired CT after the PPA ends in 2031. Acquiring Lancaster would be an alternative to construction of a new CT. Alternatively, if the pumped hydro was available at a lower price, it could be an alternative. Because there is no capacity shortfall in 2027, the need for Montana wind is
delayed until the Northeast CT is retired and no Long Lake second power house is required, and is exchanged for additional solar and geothermal toward the end of the plan. Portfolio #14 financial results are not included in many of the following tables. The results may give counterparties specific information negating the benefits of potential RFP bidding. Appendix J is confidential to include these estimates.
Table 12.14: Least Cost Plan with Lancaster Extended Five Years
Montana wind 2022 100 NW wind 2022 100 NW wind 2023 100 Kettle Falls upgrade 2024 12 Colstrip 3 & 4 exits portfolio 2026 -222 Rathdrum CT 1 & 2 upgrades 2026 24 Post Falls upgrade 2027 8 Mid-Columbia hydro 2031 75 Lancaster PPA expires 2032 -257 Natural gas CT 2032 245
Northeast CTs retires 2035 -55
MT wind 2035 200
Liquid air storage (16 hours) 2038-2043 100 Wind (including PPA renewals) 2041-2043 300 Lithium-ion storage (4 hours) 2042-2044 150 Solar w/ storage 2045 100 Storage for solar (4 hours) 2045 100 Geothermal 2045 20 Supply-side resource net total (MW) 1,100 Supply-side additions through 2045 (MW) 1,634 Demand Response through 2045 (MW) 108 Energy Efficiency through 2045 (aMW) 177

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 227 of 259
Portfolio #15: Least Cost Plan with Colstrip Unit #4 Extended to 2035 Avista does not have unilateral control of Colstrip’s eventual shutdown date regardless of
Avista’s preference because of the ownership agreement. One potential outcome is for one unit to shut down while the other unit remains in service. This scenario attempts to show the changes in the portfolio mix and cost if this outcome occurs. With one unit of Colstrip shut down in 2025 and the other continuing until 2035, the major impacts are a shift in Montana wind to match transmission availability and the selection of a modest
amount of additional long duration pumped hydro storage. Table 12.15: Least Cost Plan with Colstrip 4 Extended to 2035
Montana wind 2022 100 NW wind 2022 100 NW wind 2023 100 Kettle Falls upgrade 2024 12 Colstrip 3 exits portfolio 2026 -111 Rathdrum CT 1 & 2 upgrades 2026 24 Long duration pumped hydro 2026 225 Lancaster PPA expires 2027 -257 MT Wind 2027 100 Post Falls upgrade 2027 8 Mid-Columbia hydro 2031-2032 75 Long Lake 2nd powerhouse 2035 68 Northeast CTs retires 2035 -55
Colstrip 4 exits portfolio 2035 -111 MT wind 2037 100 Liquid air storage (16 hours) 2041-2043 75 Wind (including PPA renewals) 2042-2045 300 Lithium-ion storage (4 hours) 2044-2045 175 Solar w/ storage 2043-2044 55 Storage for solar (4 hours) 2043-2044 50

Supply-side resource net total (MW) 1,033 Supply-side additions through 2045 (MW) 1,567 Demand Response through 2045 (MW) 108 Energy Efficiency through 2045 (aMW) 182

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 228 of 259
Portfolio Summary Analysis Avista studied 15 possible portfolios, each with possible levers that can change Avista’s
decision-making process. To summarize each of these outcomes and identify common trends for resource decisions prior to 2040, Table 12.16 shows what is common between all the scenarios and identifies resources pursued in all cases. In this figure, cells with the mark of “X” indicate a selection. Wind and long duration pumped hydro storage are the only resources called out due to significant changes in results. Table 12.16: Resource Selection Matrix

PR
S
#2

#
3

#
4

#
5

#
6

#
7

#
8

#
9

#
1
0

#
1
1

#
1
2

#
1
3

#
1
4

#
1
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 229 of 259
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 25-year term along with intermediate time steps for each of the methodologies is in
Table 12.17. The table shows the results of the portfolios in tabular form including present value of revenue requirements (PVRR) for the first 10 years and 25 years and the effective rate for 2030 and 2045. Table 12.17: Portfolio Costs and Rates
Number (2021-45) (2021-30) Rate Rate
1 Preferred Resource Strategy 11,832 6,329 10.4 14.1
2 Least Cost Plan- w/o CETA 11,670 6,222 10.1 13.5
3 Clean Resource Plan - 100% net clean by 2027
(no capacity or renewable
clean by 2027 and no CTs by
hydro or Long Lake upgrade
CETA
CETA
pumped hydro costs (+35%)
credits extended
growth
economic growth

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 230 of 259
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 kWh to spread total costs over. Figure 12.3 shows the energy rates by portfolio sorted from lowest to highest. The lowest rate portfolios include scenarios without CETA or federal tax credit extensions. High economic growth also has lower rates as more energy is available to spread out all costs over.
Scenarios with Colstrip extending to 2035 (#7 and #8) have the same rate in 2030 as the PRS (#1) but slightly lower energy rates in 2045. Although the total cost is higher by $2 million each year to keep Colstrip in the portfolio through 2035 as shown in Figure 12.4. Even if CETA was not in place, the total cost is higher to keep Colstrip through 2035 is higher as shown in the change in cost between portfolio #7 and portfolio #2.
The PRS is also lower cost compared to the portfolio with only Colstrip Unit 4 being operational until 2035. The differences in order of portfolio rates and revenue requirement costs come down to energy efficiency. Both portfolios use the same load forecast, but if Colstrip exits beyond 2025, it will create the need for more energy efficiency, thereby
reducing energy sales and creating higher rates. Figure 12.3: Portfolio Average Energy Rates

One advantage of showing both the 2030 and 2045 rates, as opposed to solely analyzing the costs, is the ability to compare rate outcomes toward the end of the plan. In this example, adding more clean energy and retiring natural gas-fired plants shows a separation in rates from the other scenarios.
18.2
15.6
14.5
14.5
14.4
14.3
14.1
14.0
14.0
13.9
13.5
13.5
13.3
12.7
11.1
11.1
10.4
10.2
10.6
10.4
10.4
10.5
10.4
10.3
10.1
10.3
10.0
9.4
5. CRP- No CTs
3. Clean Resource Plan (CRP)
12. LCP Low Economic Growth
6. LCP w/o PS/Hydro
11. CRP w/ federal tax credits extended
9. LCP w/ Higher P/S cost
1. Least Cost Plan/ PRS
15. Colstrip 4 in 2035
8. Colstrip 2035 w/ CETA
13. LCP High Economic Growth
2. LCP- w/o CETA
7. Colstrip 2035 w/o CETA
10. Least Cost w/ federal tax credits extended
4. Rely on Energy Markets Only w/o CETA
Cents per kWh
2030 Rate (c/kWh)
2045 Rate (c/kWh)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 231 of 259
Figure 12.4: Portfolio Average Energy Levelized Revenue Requirement
Greenhouse Gas Analysis
The portfolios studied in the chapter all are consistent with a net reduction of greenhouse gas emissions, but the reduction timing and levels differ. Avista explored two methods to
analyze greenhouse gas emissions. Figure 12.5 shows the annual emissions in millions
of metric tons for each of the scenarios by year. Portfolios with Colstrip extending its operation beyond 2025 show higher emissions. Clean energy extensive portfolios reduce emissions to around 250,000 metric tons each year. Portfolios with no CT’s, such as Portfolio #5, still have some greenhouse gas emissions due to market transactions.

The second method of reviewing the data levelizes the 25-year emissions using the 2.5 percent discount rate identified under CETA and Avista’s 6.68 percent discount rate. This levelization shows the overall emissions of the portfolios. As expected, portfolios with higher levels of renewables have lower net emissions as compared to other portfolios.
Figure 12.5 ranks the portfolios by emissions levels.
A chart to compare both greenhouse gas emissions and costs for each portfolio is helpful to understand each portfolio’s carbon efficiency. To further this concept, Figure 12.7 compares each portfolio’s change in levelized cost and levelized emissions from Portfolio
#2. Where Portfolio #2 is a base portfolio without specific greenhouse reduction goals.
The portfolios with increasing cost for fewer emissions are in the top left quadrant. Effectively, these portfolios develop a cost per ton of emissions reduction. For example, the Avista PRS adds $44 per metric ton for emission reduction. The Clean Resource Plan
Levelized Annual Revenue Requirement (Millions)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 232 of 259
(CRP) (#3) has a higher ratio of $144 per metric ton and CRP without CTs (#5) $166 per metric ton on average for the 25 years. Portfolios with increasing costs and increasing
emissions are in the top right quadrant. These portfolios are where Colstrip operates longer. The lower right quadrant of higher emissions and lower cost is rare and only occurs with no resource additions in Portfolio #4. The bottom left quadrant of lower cost and lower emissions is the best-case scenario, but this only results with lower loads due to low economic growth or federal tax credit extensions.
Figure 12.5: Portfolio Annual Greenhouse Gas Emissions

1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits extended
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
15. Colstrip 4 until 2035
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 233 of 259
Figure 12.6: Levelized Greenhouse Gas Emissions
Figure 12.7: Change in Greenhouse Gas Emissions Compared to Change in Cost

11. CRP w/ federal tax credits extended
5. CRP- No CTs
3. Clean Resource Plan (CRP)
9. LCP w/ Higher P/S cost
1. Least Cost Plan/ PRS
10. Least Cost w/ federal tax credits extended
13. LCP High Economic Growth
12. LCP Low Economic Growth
6. LCP w/o PS/Hydro
14. LCP w/ Lancaster PPA
2. LCP- w/o CETA
15. Colstrip 4 until 2035
4. Rely on Energy Markets Only w/o CETA
8. Colstrip 2035 w/ CETA
7. Colstrip 2035 w/o CETA
Levelized Greenhouse Gas Emisisons (Millions)
Ch
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n
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e

i
n

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i
z
e
d

C
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f
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o

#
2

(M
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l
i
o
n
s
)
Change in Levelized GHG Emissions from Portfolio #2 (Millions)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 234 of 259
Risk Analysis
Avista’s 500 simulations of market prices allow Avista to study the portfolio cost in different market conditions and allow the potential to create portfolios that lower risk for customers. Portfolio costs can include the standard deviation of cost and tail risk to measure each
portfolio’s risk.
Avista typically shows its cost versus risk metrics graphically with cost on the x-axis and risk on the y-axis. This method shows the tradeoff between cost and risk. Avista also developed portfolios to compare to the least cost portfolio by creating an efficient frontier
of portfolios (see Figure 12.8). This method shows the lowest cost portfolios for each level
of risk. This is helpful in showing the differences in handpicked resource strategies risk compared to a more optimal portfolio development. Figure 12.8: Conceptual Efficient Frontier Curve

Costs increase as you attempt to lower risk of portfolios. The optimal point on the Efficient Frontier depends on the level of acceptable risk. No best point on the curve exists, but Avista prefers points where small incremental cost additions offer larger risk reductions.
Portfolios to the left of the curve are more desirable but do not meet the planning
requirements or resource constraints. Examples of these constraints include environmental costs, regulation, and the availability of commercially viable technologies. Portfolios to the right of the curve are less efficient as they have higher costs than a portfolio with the same level of risk. PRiSM meets all deficit projections with new
resources of the actual sizes available in the marketplace and does not rely on market
purchases.
Portfolio
outside of
portfolio
constraintsRi
s
k
Cost
Least cost-
highest risk
portfolio
Highest cost-least risk portfolio
Inefficient portfolio
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 235 of 259
Figure 12.9 shows the mapping of the levelized portfolio cost and 2030 risk. The black line represents the portfolios along the Efficient Frontier; including the PRS, which is the
lowest cost and highest risk portfolio. There are portfolios to the left of the Efficient Frontier, these portfolios are scenario where cost are lower either due to less regulation or where tax credits are available. There are portfolios to the right of the Efficient Frontier as well that may be an efficient method to reduce risk, but they may not meet other objectives such as greenhouse gas emissions reductions. The portfolios with higher risk
typically have less resource additions such as Portfolio #4 and Portfolio #2. Figure 12.9: Portfolios Compared to the Efficient Frontier
Avista selected two other risk measurements besides standard deviation from the Efficient Frontier analysis. The second metric is tail risk; in this case, it is the 95th percentile of costs minus the mean cost or TailVar95. Figure 12.9 shows this example
with portfolios sorted from lowest risk to highest risk. The tail risk does not include the social cost of carbon (SCC). The other risk metric is similar to TailVar95, but it includes the tail risk added to the expected costs. Figure 12.10 shows this methodology. The data includes examples both
with and without the SCC. In Figure 12.11 the blue bars show the total present value of revenue requirement (PVRR) with risk at the 95th percentile without the SCC; the orange triangles include the same cost but with the SCC. The circle value and the yellow diamond is the cost plus one standard deviation with and without the SCC.
1. Least Cost Plan/ PRS
20
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 236 of 259
The TailVar95 analysis shows portfolios with higher penetrations of renewables have lower tail risk due to fixed pricing of the resources. Also there are lower market risks of
portfolios with additional coal generation. Figure 12.10: Portfolio TailVar95 Analysis

Taking into account total cost with risk, Figure 12.11 shows the lowest risk with cost is the
portfolio with tax credits extended or lower loads. It is interesting that the Colstrip extended to 2035 Portfolio #8 has a slightly lower risk adjusted cost then this portfolio unless the SCC is included in the cost. The higher cost portfolios include higher loads, and heavy clean energy portfolios, even in cases considering the SCC.
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8. Colstrip 2035 w/ CETA
11. CRP w/ federal tax credits extended
3. Clean Resource Plan (CRP)
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 237 of 259
Figure 12.11: Portfolio PVRR with Risk Analysis

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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 238 of 259
Market Price Sensitivities
Another way to measure risk for each portfolio is to compare its cost under different specific market conditions rather than rely 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, while fixing the major risk variables
such as hydroelectric and natural gas at expected averages. Scenario 2 assumes a future without CETA (to be able to calculate the cost of that law), Scenario 3 is low natural gas prices, Scenario 4 is high natural gas prices, and Scenario 5 is the SCC as a tax across the entire Western Interconnect.

The following tables show the change in cost and greenhouse emissions given these pricing sensitivities. Table 12.18 shows the cost changes compared to the Expected Case revenue requirements from the deterministic price forecast. In general, the “No CETA” scenario increases costs due to slightly higher market prices, increasing Avista’s cost to
serve customers. The “Low NG Prices” scenario generally lowers cost and “High NG
Prices” generally increases total costs. The final scenario of including the SCC as a tax increases costs in all portfolios. Table 12.19 shows the cost change to the PRS for both the stochastic market forecast
and the deterministic scenarios. The scenarios generally follow the same cost changes
as the Expected Case with the exception of the SCC tax scenario where additional renewables stabilize the cost. Portfolios with less or more natural gas-fired resources have costs that follow changes in natural gas prices.
Table 12.20 shows greenhouse gas emissions changes compared to the deterministic
Expected Case. The “No CETA” scenario generally increases emissions as less renewables are in the system and natural gas-fired generation is dispatching more aggressively. The lower natural gas price scenario also increases emissions, as it is cheaper to run natural gas-fired generation. Since Colstrip closes in 2025 (early in the
study), the lower coal generation dispatch does not have a major impact on total
emissions. Higher natural gas prices results in a mixture of results with both higher and lower emissions depending on the scenario. While the SCC tax scenario lowers emissions by large amounts.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 239 of 259
Table 12.18: Change in Cost (PVRR) Compared to Expected Case
Table 12.19: Change in Cost (PVRR) Compared to PRS

1. Least Cost Plan/ PRS 0.6% -3.0% 2.6% 10.5%
2. LCP- w/o CETA 0.8% -4.4% 4.3% 15.5%
3. Clean Resource Plan (CRP)0.1% -2.3% 1.7% 7.6%
4. Rely on Energy Markets Only w/o CETA 0.4% -5.8% 6.0% 19.5%
5. CRP- No CTs 0.2% -2.0% 1.5% 7.6%
6. LCP w/o PS/Hydro 0.3% -3.7% 3.5% 12.4%
7. Colstrip 2035 w/o CETA 0.7% -3.8% 3.0% 14.8%
8. Colstrip 2035 w/ CETA 0.7% -2.7% 2.2% 13.1%
9. LCP w/ Higher P/S cost 0.4% -3.1% 2.8% 10.5%
10. Least Cost w/ federal tax credits extended 0.6% -3.1% 2.7% 10.8%
11. CRP w/ federal tax credits extended 0.1% -2.3% 1.8% 7.9%
12. LCP Low Economic Growth 0.4% -3.0% 2.7% 11.3%
13. LCP High Economic Growth 0.8% -3.2% 2.9% 10.9%
15. Colstrip Unit 4 through 2035 0.6% -2.8% 2.4% 11.9%
2. LCP- w/o CETA -1.4% -1.8%-1.6% -3.3% -0.1% 2.7%
3. Clean Resource Plan (CRP)5.1% 5.3% 4.7% 6.0% 4.4% 2.5%
4. Rely on Energy Markets Only w/o CETA -5.5% -6.4% -6.6% -9.1% -3.3% 1.2%
5. CRP- No CTs 6.2% 6.4% 5.9% 7.4% 5.2% 3.5%
6. LCP w/o PS/Hydro -0.1% 0.0% -0.3% -0.8% 0.9% 1.8%
7. Colstrip 2035 w/o CETA -0.8% -1.0% -1.0% -1.9% -0.6% 2.9%
8. Colstrip 2035 w/ CETA 0.2% 0.3% 0.4% 0.6% -0.1% 2.7%
9. LCP w/ Higher P/S cost 0.3% 0.3% 0.1% 0.1% 0.4% 0.3%
10. Least Cost w/ federal tax credits extended -2.7% -2.7% -2.7% -2.8% -2.6% -2.4%
11. CRP w/ federal tax credits extended 1.4% 1.7% 1.1% 2.4% 0.8% -0.7%
12. LCP Low Economic Growth -2.6% -2.8% -3.1% -2.9% -2.7% -2.2%
13. LCP High Economic Growth 2.3% 2.5% 2.6% 2.2% 2.8% 2.8%
15. Colstrip Unit 4 through 2035 0.2% 0.3% 0.3% 0.4% 0.1% 1.6%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 240 of 259
Table 12.20: Levelized Greenhouse Gas Emissions vs. Expected Case
Table 12.21: Change in Levelized Greenhouse Gas Emissions Compared to the PRS

1. Least Cost Plan/ PRS 3.0% 8.7% -1.1% -36.8%
2. LCP- w/o CETA 5.2% 8.2% -0.8% -32.4%
3. Clean Resource Plan (CRP)1.6% 11.2% -1.1% -43.9%
4. Rely on Energy Markets Only w/o CETA 2.7% 3.7% -3.6% -29.3%
5. CRP- No CTs 2.6% 11.2% 0.3% -43.3%
6. LCP w/o PS/Hydro 1.9% 8.2% -4.6% -36.0%
7. Colstrip 2035 w/o CETA 4.2% 1.8% 0.0% -53.6%
8. Colstrip 2035 w/ CETA 3.9% 2.0% 0.8% -57.2%
9. LCP w/ Higher P/S cost 1.7% 7.9% -2.9% -37.2%
10. Least Cost w/ federal tax credits extended 2.7% 2.7% -1.5% -37.1%
11. CRP w/ federal tax credits extended 1.9% 11.6% -0.8% -44.3%
12. LCP Low Economic Growth 1.8% 6.8% -2.7% -35.3%
13. LCP High Economic Growth 4.0% 10.2% 4.0% -37.4%
14. LCP w/ Lancaster PPA 2.6% 7.5% -4.5% -38.3%
15. Colstrip Unit 4 through 2035 3.6% 4.5% 0.2% -49.8%
2. LCP- w/o CETA 30.0% 24.1% 26.8% 23.6% 24.4% 32.9%
3. Clean Resource Plan (CRP)-23.8% -20.4% -21.5% -18.6% -20.5% -29.3%
4. Rely on Energy Markets Only w/o CETA 33.5% 26.5% 26.2% 20.7% 23.3% 41.5%
5. CRP- No CTs -23.9% -20.7% -21.0% -18.9% -19.6% -28.8%
6. LCP w/o PS/Hydro 9.2% 8.0% 6.9% 7.5% 4.2% 9.3%
7. Colstrip 2035 w/o CETA 86.0% 88.2% 90.5% 76.3% 90.2% 38.2%
8. Colstrip 2035 w/ CETA 64.1% 71.3% 72.8% 60.7% 74.5% 15.9%
9. LCP w/ Higher P/S cost -0.3% -0.8% -2.1% -1.5% -2.7% -1.3%
10. Least Cost w/ federal tax credits extended 0.2% -0.1% -0.4% -5.6% -0.5% -0.6%
11. CRP w/ federal tax credits extended -24.6% -21.1% -21.9% -19.0% -20.9% -30.4%
12. LCP Low Economic Growth 4.5% 2.7% 1.5% 1.0% 1.0% 5.1%
13. LCP High Economic Growth 1.5% 1.5% 2.5% 2.9% 6.7% 0.5%
14. LCP w/ Lancaster PPA 16.6% 15.7% 15.2% 14.4% 11.6% 12.9%
15. Colstrip Unit 4 through 2035 33.0% 36.2% 37.0% 31.0% 37.9% 8.3%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 241 of 259
Electrification Scenario
Recently, there is a movement to develop policies supporting the electrification of energy to reduce greenhouse gas emissions. While there is potential to lower emissions with this strategy, there are serious consequences and considerations requiring analysis prior to
pursuing the strategy. Specifically, analysis will be required to determine the costs to the
power system and homeowners, but also if technology exists to reliably serve customers’ new heating and transportation needs. Avista considered three potential changes to the power system for this scenario. The first
change is an increase in electric vehicles (EV), the second is an increase in rooftop solar
systems, and the last is electrification of space and water heating systems away from the Local Distribution Company’s (LDC) natural gas system. Avista modeled each of these potential load scenarios as possible changes of customer adoption over time. The descriptions of specific changes to the assumptions and load is below.
Electric Vehicles The Expected Case (used in the PRS) includes a significant increase in EVs throughout the 25-year forecast; see Table 12.12 identified as the “High EV Penetration”. In 2021, the study includes nearly 1,200 vehicles in the service territory increasing to over 100,000
in 2045. This assumes an 18.7 percent year-over-year increase, whereas the
electrification scenario increases this trajectory to a 23 percent year-over-year increase for 250,000 EVs by 2045. This IRP estimates the greenhouse gas emissions reductions using the number of new EVs, new load and the average emissions rates per vehicle.
For the load estimate, additional kWh per vehicle increases over time to account for larger
battery systems. Although, the winter peak increase per vehicle remains flat to simulate the effect of time of vehicle changing away from peak hours. Figure 12.13 shows the total change in energy and peak load. In 2030, the higher EV penetration increases energy load by only 1 aMW, but by 2045, when our higher EV penetration shows an exponential
growth rate, energy load increases to 65 aMW and peak load increases by 107 MW. The Expected Case assumes regional greenhouse gas emissions from petroleum for transportation fall by nearly 40,000 metric tons in 2030, growing to 530,000 metric tons by 2045. In the higher electrification scenario, petroleum emissions fall by 59,000 metric
tons by 2030, and 1,300,000 metric tons by 2045. The emissions reductions from EVs would not reduce utility emissions, but they highlight the magnitude of the greenhouse gas emissions reductions for the region from the electrification of transportation.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 242 of 259
Figure 12.12: Electrification Scenario: EV Forecast Comparison
Figure 12.13: Electrification Scenario: EV Load Forecast Comparison

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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 243 of 259
Rooftop Solar The electrification scenario assumes additional rooftop solar penetration. The drivers for
additional rooftop solar could be either economically driven by lower installation cost, higher utility cost, or even government subsidies. Regardless of the reason for the increase, understanding the effects to load is important to understand. The estimate of the load reduction includes assumptions on the number of solar systems, the size of the systems, and the efficiency of the systems. This scenario uses the Expected Case’s load
forecast for system size and efficiency, but the number of systems increases by changing the penetration rate of customers installing solar. The scenario assumes the penetration rate doubles by 2030; but by 2045, the penetration is 10 percent compared to 2.2 percent in the Expected Case. Figure 12.14 shows the rooftop solar customer count estimates for this scenario compared to the Expected Case. This scenario shows an exponential
growth of rooftop solar compared to a linear growth in the Expected Case. The change in load for solar is a simple calculation using system size and efficiency compared to the total number of systems. Figure 12.16 shows these total estimates. In this scenario, average load falls by an additional 2 aMW by 2030, but as the solar
penetration growth intensifies by 2045, load is approximately 47 aMW lower, and nearly 100 aMW lower at summer peaks. Although, load falls in both annual energy and during the summer, Avista assumes no winter peak reduction due to timing of winter peak load occurring when it is dark. Future solar systems could have storage to shift some of the load to off peak periods. Although possible with residential storage, the net system effect
would be small due to reliability periods of concern typically coinciding with low solar output and the relatively short term residential storage devices duration may not be long enough.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 244 of 259
Figure 12.14: Electrification Scenario: Rooftop Solar Customer Count Comparison
Figure 12.15: Electrification Scenario: Rooftop Solar Load Changes

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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 245 of 259
Space and Water Heating Electrification The last component of the electrification scenario is to understand how load would change
if customers switch from natural gas to electric for space and water heating. Avista has encouraged customers to switch to natural gas for benefits including comfort, convenience, and lower heating cost. Further, it is a more efficient method of delivering heat in cold periods compared to burning natural gas in a CT to make electricity and transmit it to customers. The downside to natural gas is the associated greenhouse gas
emissions. To estimate the impact to loads is a challenge specifically to peak loads. The load conversion estimate begins with an estimate of natural gas penetration rates from the Expected Case’s load forecast. In this forecast, the 70 percent penetration rate
assumption remains flat. Beginning in 2026, the penetration rate begins to decline until nearly 100,000 customers convert from natural gas to electric. This methodology simulates new homes constructed as all electric homes and existing homes slowly converting as older natural gas systems require replacement. The natural gas penetration rate included in the load forecast allows an estimate for the reduction in load from the
number of customers on average; this estimate is approximately 15,000 additional kWh per electric customer annually. Figure 12.16: Electrification Scenario: Electric Customer’s with Natural Gas

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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1, Page 246 of 259
The larger challenge in the scenario is to understand how the load shape and peak loads will change with customers moving to electric space and water heating. Much of this
estimate deals with efficiency of end use consumption of electricity and natural gas today. This begins with Figure 12.17, which shows the historical natural gas load from Avista’s system (Washington and Idaho). Since the primary use of natural gas is for heating, the use is primarily in winter months.
The remaining natural gas usage is for commercial/industrial processes and water heating throughout the rest of the year. The next step identifies customer classes and uses by each temperature, then finally the efficiency of each process at each temperature. For example, a heat pump is 150 percent efficient compared to strip electric heat at 35 degrees, but at five degrees Fahrenheit, the heat pump is only 100 percent efficient and
assumed to be equal to strip heat or an electric furnace. Given the IRP’s focus on reliability in winter peak months, the efficiency rates in cold temperatures such as 5 degrees is most important. Figure 12.17: 2017 Avista’s Core Natural Gas Load

Avista uses an estimated efficiency rate in ten-degree temperature blocks to estimate the
added load, see Figure 12.18. As temperatures get colder, the amount of kWh required per therm each day increases. These estimates calculate the amount of load on the natural gas system by splitting it between water heat, space heat, and process; then assigning efficiency rates for each of the temperature periods to each end use type. For
the January peak day from 2017, the 100,000 customers would require 681 MW on the
peak hour. Figure 12.20 shows these estimates.
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Figure 12.18: Natural Gas to Electric Efficiency Rates Based on Daily NG use
To check the reasonableness of the potential load requires additional analysis on a per customer basis. If 100,000 customers must add both an electric furnace and a water heater to their home/business, it would result in 1,000 MW of potential load just for furnaces assuming each furnace is 10 kW2. This assumes all the equipment was running
at the same time, which is unlikely. In addition to the furnace load is the water-heating load. Water heaters are typically 5.5 kW3 each, thus adding 550 MW if all water heaters are running totaling 1,550 MW of potential peak load. Assuming historical diversity on an average peak day4 the new load is 681 MW, although this maximum potential could hold in lower temperature days. With higher loads, sensitivity per unit of temperature could
require Avista to increase its planning margin and require additional capacity resources. Overall, this analysis determined the load shift by estimating the average change in consumption from the total system, then backed into how the energy would be shaped by day (and by hour) based on historical natural gas usage and end uses. Avista hopes to
see additional studies completed across the region to study this effect in detail and to understand the externalities resulting from major fuel changes. Figure 12.19 shows the resulting load effects of the natural gas conversions. The chart shows the steady growth
2 Electric furnace sizes depend on building square footage and the building envelope.
3 Assumes the kWh required during resistance mode if the water heater is a heat pump model.
4 An average peak day is temperature equating to the average of the historical coldest days of each year in the Spokane temperature historic record.
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in winter peak to approximately 680 MW while the average energy is much smaller at 170 aMW. The summer impact is minor at around 56 aMW.
Figure 12.19: Electrification Scenario: Load with Natural Gas Customer Conversions
Figure 12.20 shows the total load changes for the three electrification load adjustments. The winter peak load is the largest adjustment primarily due to the heating conversions and to a smaller extent additional EVs. In 2045, the peak forecast without these
adjustments is 1,882 MW; with the adjustments, the peak increases to 2,670 MW, a 42 percent increase. This analysis only converts 100,000 customers to electric, if the remaining 200,000 customers were electrified the added peak load will exceed 4,700 MW or 250 percent of the current forecast for 2045. Summer peak does not increase much due to the additional rooftop solar installations. Overall, the challenge to serve customers
with this load profile is to have a reliable source of energy for meeting winter loads between October and April.
Energy
Winter Peak
Summer Peak
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Figure 12.20: Electrification Scenario: Total Load Changes

The change in load requirements is not the only important consideration in the electrification scenario. First, there will be impacts to the remaining natural gas customers. The impacts are to the remaining customers who must pay for a system designed for a larger customer base. There will also be carbon emission reductions from
the reduction in direct natural gas consumption, estimated to reach 430,000 metric tons
by 2045. Additional analysis to quantify the new transmission requirements to move the new generation to the added load will be necessary. Further, each of Avista’s distribution feeders could double or triple in load requirements requiring new feeders. The last impact is the cost to homeowners. Electric only customers will pay higher heating costs using
current prices as compared to today’s natural gas prices but also pay higher rates to
construct new generation to serve the new load. In addition, there is a cost to convert residential equipment to electric and potentially a cost to rewire existing homes to handle the additional electric load. Another concern customers may have is the lack of a diversified energy source for back up. Many customers use natural gas heating in the
event of storm related power outages; without this option, customers may also have to
invest in new secondary heating options. The year 2045 is the easiest to illustrate the costs and benefits to the power system for
this scenario, along with the associated emission reductions, due to the earlier ramping
into the end goals of load changes. The estimated cost increase in 2045 is $243 million above the cost of the PRS; this includes the avoided natural gas commodity costs but does not include the change in petroleum purchases or the cost for customer’s rooftop solar systems. This cost translates to a rate of 14.8 cents per kWh, compared to 14.1
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cents per kWh from the PRS. The rate impacts are less than compared to total cost divided by the additional kWh sold.
The main reason for the change in the power system cost is the cost to add new generating resources to cover peak loads and meet the clean energy goals. Although the 2045 goal of 100 percent clean energy all the time is not met as the cost exceeds the 2 percent threshold, and the storage required to meet the added loads during the winter
would need to be studied for reliability analysis and would likely exceed durations in the “weeks” time period. Absent changes in technology, Avista would need an additional 700 MW of natural gas-fired turbines, 700 MW of solar with 300 MW of 4-hour lithium-ion storage, and 400 MW of liquid air storage5. Although even with the natural gas-fired electric generation additions, emissions would still fall, as much of this additional
generation is only required during peak periods. The emissions in the PRS, including the natural gas emissions for the 100,000 LDC customers6, and the included emissions reductions from the avoided petroleum is a net increase of 310,000 metric tons. In the electrification scenario, utility emissions increase
to just under 600,000 metric tons, but EV emissions lower by a total of 1.3 million metric tons (or an additional reduction of 770,000 metric tons); the LDC natural gas emissions reduce to zero from 430,000 metric tons. The net change in emissions is approximately one million metric tons as shown in Table 12.22. Using these estimates, the 2045 implied cost of carbon reduction is $241 per metric ton, not including the costs for the rooftop
solar, additional transmission and distribution costs, and the associated customer home/business equipment conversion costs. The social cost of carbon estimate in 2045 is $179 per metric ton. Table 12.22: Electrification Scenario: Emission Changes in Millions of Metric Tons
Electric Utility 0.41 0.60 +0.19
Avoided Petroleum -0.53 -1.30 -0.77
LDC Natural Gas 0.43 0.00 -0.43
Total Emissions 0.31 -0.70 -1.01
When considering the remaining 24 years of the study, the total increase in cost is $700 million or 6 percent, the total emissions reduction using the 2.5 percent discount rate equates to three million metric tons, for a 25-year average cost of $228 per metric ton7 of
carbon emissions reduction. Using the results of this study in total, the justification for
electrifying all of these systems is not an effective use of customer money to reduce
5 Avista has not conducted a reliability study to determine if this portfolio would meet reliability standards.
6 This analysis does not consider emissions from the remaining natural gas customers.
7 If discounted at Avista’s discount rate, the emissions cost per ton would be $483 per metric ton.
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greenhouse gas emissions due to the investments required for small emission reductions. Although a look at the individual electrification policies may lead to different conclusions,
such as electrifying segments of the transportation sector. The installation of rooftop solar does not affect Avista’s resource strategy due to its lack of winter capacity savings. Although, rooftop solar lowers retail sales and pushes fixed costs to other customers unless there is rate reform. The case for electric vehicles seems
to have potential as an effective measure of reducing greenhouse gas emissions without a material impact to the power system,8 and depending on the cost to consumers for the transition in vehicle types, it could make the most sense for reducing regional emissions. The movement to electrify space and water heat is the most expensive endeavor of the three concepts due to the significant winter capacity requirements. Perhaps identifying
additional energy efficiency, renewable natural gas systems, and potential carbon capture on end use consumption is better use of limited customer funds to make sure Avista’s customers have a cost effective method of keeping warm in the winter.

8 This insight uses Avista’s current small amount of EVs on the system and its opinion may change as
additional vehicles effect on the load materializes especially in the winter as additional energy/capacity may exceed current expectations.
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13. Action Items

The IRP is an ongoing and iterative process balancing regular publication timelines with pursuing the best resource strategy for the future. 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 IRP Action Plan and provides the 2020 Action Plan. 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.
o Avista included upgrade options for this IRP analysis for Post Falls, Long Lake, Rathdrum, and Kettle Falls. This IRP also evaluated the potential for upgrades at Monroe Street, Upper Falls, and Cabinet Gorge. The results of the study were to
pursue upgrades at each of the facilities studied. Avista 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 ability to provide non-power supply benefits. o This IRP includes a range of storage resource technologies and durations. The IRP studied the reliability benefits of different storage durations. Avista included pumped
hydro, liquid-air, and lithium-ion in the 2020 PRS. During this IRP cycle, storage
costs continued to change and new technologies are being developed. Avista will continue to analyze new storage options as a resource in addition to continuing its process in optimizing the transmission and distribution systems to utilize storage when helpful 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. o Avista’s officers approved joining the EIM on April 15, 2019 and the Company plans
to go live with the EIM on April 1, 2022. Avista shared this update at the fifth TAC
meeting on October 15, 2019. As part of joining the EIM, Avista expects to spend $21 to $26 million to enter the market and an additional $3.5 to $4.0 million each year thereafter. The EIM will require at least 12 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 $5.8 million per year. The complete EIM presentation shared with
the TAC is in Appendix A.
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• Monitor regional winter and summer resource adequacy, provide TAC with additional Avista
LOLP study analysis.
o The second TAC meeting included a presentation regarding Avista’s resource adequacy methodology and preliminary results of our 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. Appendix A includes the slides presented to the TAC and Chapters 9 and 11 include results from Avista’s reliability studies.
• Update the TAC regarding progress on the Post Falls Hydroelectric Project redevelopment.
o Avista concluded in the 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 higher ratings to 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. Those presentations are available in Appendix A.
• Perform a study to determine ancillary services valuation for storage and peaking technologies using intra hour modeling capabilities. Further, use this technology to estimate
costs to integrate variable resources.
o Avista conducted studies regarding the benefits of pumped hydro storage and flow batteries and shared results with the TAC at its fifth meeting. Avista believes this area of analysis is important to meet future needs of the system and requires tools to correctly identify the costs and benefits. Avista plans to conduct additional
analysis once sub-hourly modeling is available in the ADSS system. Without this expanded ADSS functionality, the analysis will use similar methods of arriving at benefits from previous studies.
• Monitor state and federal environmental policies affecting Avista’s generation fleet.
o Avista continues to monitor and participate in the development of state and federal environmental policies affecting Avista’s generation fleet. Details providing updates about the ongoing impacts and changes to these policies are available in Chapter 4.
Energy Efficiency and Demand Response
• Determine whether or not to move the Transmission and Distribution (T&D) benefits estimate to a forward looking value versus a historical value.
o Avista is continuing to use the historical value method for T&D benefits with modifications to include its net plant values on a proforma basis. A forward looking methodology would be more precise as it aligns future plant values with the time period of the benefits received; however, the timing of the analysis needed to
quantify future plant investments as it relates to energy efficiency becomes less
reliable the further out it is forecasted. For this reason, the Company concludes a historic value method to be the preferred methodology. In order to incorporate an element of forward looking values, Avista includes its net plant on a proforma basis
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to better align the values with future T&D benefit periods. For DR’s potential for offsetting T&D investments, Avista needs to make progress to analyze DR potential
at the feeder level or identify DR opportunities on feeders with the need for additional investment.
• Determine if a study is necessary to estimate the potential and costs for a winter and
summer residential demand response program and along with an update to the existing commercial and industrial analysis.
o Applied Energy Group (AEG) conducted a DR potential study for Avista’s service territory. The study included programs for residential, commercial, and industrial customers. AEG presented the DR programs at the third TAC meeting in April 2019.
Chapter 6 includes an overview of these DR programs. Avista also identified many of these programs as cost effective and they are included in the PRS described in Chapter 11.
• Use the utility cost test methodology to select conservation potential for Idaho program options. o 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 located in Chapter 5.

• Share proposed energy efficiency measure list with Advisory Groups prior to CPA completion. o Avista provided a list of energy efficiency measures to TAC members in April 2019.
The list is also available as Appendix E. Transmission and Distribution Planning
• Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for
transmission service to bundled retail native load.
o Avista has maintained its existing transmission rights on its system and any transmissions system it purchases rights from to serve native load.
• Continue to participate in BPA transmission processes and rate proceedings to minimize costs of integrating existing resources outside of Avista’s service area. o 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. o Avista staff participates in and leads many regional transmission efforts including the Columbia Grid and the Northern Tier Transmissions Group Forums.
• IRP & T&D planning will coordinate on evaluating opportunities for alternative technologies to solve T&D constraints. o Avista conducted a pilot of whether or not a distribution project could be modeled within PRiSM to co-optimize the power system along with the needs of the T&D
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system. Chapter 8 discusses this analysis. Avista plans to continue this analysis in future IRPs.
2020 IRP Two Year Action Plan
Avista’s 2020 PRS provides direction and guidance for the type, timing, and size of future
resource acquisitions. The 2020 IRP Action Plan highlights the activities Avista will undertake between IRP filings. These activities include both resource acquisition processes, regulatory filings, and analytical efforts for the next IRP. Progress and results for the 2020 Action Plan items are reported to the TAC and the results or progress will be included in Avista’s next IRP.
This Action Plan includes input from Commission Staff, Avista’s management team, and
members of the TAC. 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 identifies long duration pumped hydro storage as the capacity resource deficits. Avista will continue engaging with pumped hydro developers regarding this resource. 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 made as new information is available.
• 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. Avista will conduct transmission and air permitting studies to prepare for this contingency. Avista expects this process to take at least two years.

• 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.
• 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 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.
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• This IRP forecasts the Northeast CT will retire in 2035. Avista will continue to evaluate this
date as it operates the facility and will provide the TAC with additional analysis and information regarding the preferred retirement date.
• This IRP’s 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 answer to the closure date. Avista will continue evaluating this analysis and work with the other owners for the course of action to
meet state objectives and meet the needs of all of Avista’s customers.
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 if and when sub-hourly modeling is functional in Avista’s ADSS software. Avista’s timeline for this analysis is to be completed in 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 no clearly accepted standard for this area of research.

• 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 or not using a third party forecast,
along with an internally developed dispatch model, is a better approach to inform the resource planning effort.
• 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 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.

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2020 Electric Integrated
Resource Plan Appendices
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Table of Contents
Appendix A – 2020 IRP Technical Advisory Committee Presentations (Page 1)
Technical Advisory Committee Meeting 1 Presentations (Page 2)
Technical Advisory Committee Meeting 1 Minutes (Page 85)
Technical Advisory Committee Meeting 2 (Page 93)
Technical Advisory Committee Meeting 2 Minutes (Page 200)
Technical Advisory Committee Meeting 3 (Page 209)
Technical Advisory Committee Meeting 3 Minutes (Page 365)
Technical Advisory Committee Meeting 4 (Page 373)
Technical Advisory Committee Meeting 4 Minutes (Page 515)
Technical Advisory Committee Meeting 5 (Page 524)
Technical Advisory Committee Meeting 5 Minutes (Page 625)
Technical Advisory Committee Meeting 6 (Page 633)
Technical Advisory Committee Meeting 6 Minutes (Page 733)

Appendix B – 2020 Electric IRP Work Plan (Page 748)

Appendix C – Confidential Historical Generation Operation Data (Page 756)

Appendix D – AEG Conservation Potential Assessment (Page 757)

Appendix E – Conservation Potential Assessment Measurement Assumptions
(Page 933)

Appendix F – Resource Adequacy in the Pacific Northwest by E3 (Page 934)

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Appendix G – New Resource Table for Transmission (Page 1044)

Appendix H – New Resource Cost Assumptions (Page 1046)

Appendix I – Black and Veatch Renewable Resource and Storage Study (Page
1047)

Appendix J – Confidential Report of Portfolio #14 (Page 1054)
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2020 Electric Integrated
Resource Plan
Appendix A – 2020 Technical
Advisory Committee
Presentations and Meeting
Minutes
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2019 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda Wednesday, July 25, 2018 Conference Room 130
Topic Time Staff
Introductions 9:00 Lyons TAC Expectations and Process Overview 9:05 Lyons 2017 IRP Acknowledgements & Policies 9:30 Gall Break 10:15

Demand and Economic Forecast 10:30 Forsyth

Lunch 12:00 2017 Action Plan Updates 1:00 Gall 2019 IRP Draft Work Plan 1:30 Lyons Break 2:15

Hydro One Merger Agreements 2:30 Gall

Adjourn 3:00
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2019 Electric IRP
TAC Meeting Expectations
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
July 25, 2018
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Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next two years
•Current and projected load & resource position
•Preferred Resource Strategy (PRS)
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Expected case
•Market and portfolio scenarios for uncertain future
events and issues
2
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Integrated Resource Planning (Cont)
•Requires significant modeling and assumptions
–Fuel prices
–Economic activity
–Policy considerations
–Resource costs
–Energy efficiency
•Action Items –areas for more research in the next IRP
•This is not an advocacy forum
•Not a forum on a particular resource, resource type or
any particular issue
•Supports rate recovery, but not a preapproval process
3
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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 in all or some of the process
•Open forum, but we need to stay on topic to get through the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the studies we can do
–The earlier study requests are made, the more accommodating we can be
–January 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
4
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Today’s Agenda
•9:00 –Introduction and TAC Expectations and Process
Overview, Lyons
•9:30 –2017 IRP Acknowledgments and Policies, Gall
•10:15 – Break
•10:30 –Demand and Economic Forecast, Forsyth
•12:00 –Lunch
•1:00 –2017 IRP Action Plan Updates, Gall
•1:30 –2019 IRP Draft Work Plan
•2:15 – Break
•2:30 –Hydro One Merger Agreements, Gall
•3:00 –Adjourn
5
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TAC Expectations
•Avista:
–Input about assumptions and areas to study
–Five TAC meetings with agendas that may change
based on input
–Topics covered later today in the Draft Work Plan
•TAC Members:
–What are your expectations?
–Comments or questions about the process
6
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2017 Electric IRP Commission Acknowledgement Update
James Gall, IRP Manager
July 25, 2018
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Idaho
•Idaho Commission acknowledged the 2017 IRP on February 1, 2018 in order
No. 33971 of AVU-E-17-08.
•Comments were provided by the Commission Staff, Idaho Conservation
League (ICL), and 23 members of the public.
•The Commission in this order confirms … “The appropriate place to
determine the prudence of the IRP or the Company’s decision to follow or not
follow it, and the validation of predicted performance under the IRP, will be a
general rate case or another proceeding in which the issue is noticed.”
2
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Specific Idaho Staff Comments (highlights)
•Scenarios should include renewing the Lancaster contract.
•Clearly state how the Company’s portfolio complies with the EPA’s Clean Power Plan.
•Concern with natural gas prices being "extremely low throughout the entire planning period”.
•Failed to provide evidence supporting its claim "that coal price risk is not a significant factor
for Colstrip operations.”
•Continue analyzing alternatives and cost mitigation strategies for Colstrip.
•Regarding Colstrip, specify significant capital investments required for plant operation and
provide a more transparent assessment of the costs and availability of fuel for the plant.
3
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Specific ICL Comments (highlights)
•Asks the Commission to direct Avista to include a "thorough and detailed discussion" in its 2019 IRP, of
the policies and financial plans of the utility co-owners of Colstrip Units 3 and 4, and their impact on the
cost of producing and distributing electricity from Avista's share of Units 3 and 4.
–Such discussion should include analysis of provisions in Puget Sound Energy's (PSE) 2017
settlement with the Washington Utilities and Transportation Commission that (1) changed the
depreciation schedule for Units 3 and 4 from 2045 to 2027; and (2) allocated $10 million for
transition funds to the community of Colstrip.
•Recommends Avista include analysis of Oregon State Bill 1547, directing PGE and PacifiCorp to end
distribution of coal-generated electricity in Oregon by 2030.
•Provide a more transparent accounting and explanation" of how Avista's AURORA and PRiSM models
work.
•Avista provide a more thorough analysis "of the fuel price of coal at Colstrip and a forecasted range of
price volatility over the 20-year timeframe of the 2019 IRP."
4
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Customer Comments in Idaho
•The Commission conducted a public telephone hearing at which 18 people
testified, most of whom were Avista customers.
•The hearing participants testified about retiring Colstrip early, switching from
coal to renewables, and other environmental concerns.
•The Commission also received 23 written comments.
•Most comments opposed investing in Colstrip, although a few supported it.
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 16 of 1057
Specific Idaho Recommendations
•We note that customers and Staff commented on alternatives regarding the
closure of Colstrip and the inclusion in the PRS of a new gas peaker plant
after the expiration of the Lancaster agreement.
•We encourage the Company to continue evaluating all options regarding
these resources, and to consider the best interests of its customers when
developing the 2019 IRP.
•The Commission appreciates the Company's collaboration with stakeholders
in developing the 2017 Electric IRP.
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 17 of 1057
Washington 2017 IRP Acknowledgement
•Washington Commission
acknowledged the 2017 IRP on May 7,
2018 in Docket No. UE-161036
•It is important that the Commission
take this opportunity to thank the
members of the public that participated
in the Company’s Advisory Committee
process, commented in the docket,
and made oral statements at the public
meeting.
•Specific Comments:
–Colstrip Units 3 & 4
–Conservation potential assessment
–Demand response & AMI
–Forecasted natural gas prices
–Distribution system upgrade planning
–Optimal planning reserve margin
–Update legacy studies
–Portfolio scenario cost comparison
–Emissions price modeling and cost
abatement supply curve
–Public Process
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 18 of 1057
Colstrip Comments and Recommendations
1. Regarding fuel source cost and risk:
a. How dependent is Colstrip on a single-source mine for its
fuel?
b. How well understood is the supply of coal from the
Colstrip mine?
i. What are the financial risks of the type of mining
used to extract the existing coal?
ii. As the need for fuel for Colstrip declines, how does
the cost per unit of coal from the Colstrip mine
increase?
iii. What are the counter-party risks of mine operation?
iv. What risks to coal supply and coal cost does the
Joint Colstrip ownership agreement impose? How will
Avista manage them?
c. How does the fuel supply risk from Colstrip compare to
that of natural gas?
2. Does Avista have an assessment of the cost related to the
counter-party risk of Riverstone ceasing operation of its share of
Colstrip Unit 3? If not, why not?
3. Does Avista have an assessment of the cost of the counter-
party risk of Riverstone being financially unable or otherwise
failing to pay its share of decommissioning and remediation costs
for Unit 3?
4. What are the economics of the high-cost scenario under a “low
gas” scenario forecast?
5. How are the economics of Colstrip Units 3 & 4 affected if
natural gas prices continue to remain relatively flat?
6. What are Avista’s best estimates of remediation and
decommissioning costs associated with Colstrip Units 3 & 4?
7. Has the Company quantified capacity replacement costs for
Colstrip Units 3 & 4 that it could use as a basis of seeking
replacement capacity as an alternative to any large capital
investments it faces at Colstrip?
8. What is the risk of the failure of a large cost component of
Colstrip Units 3 & 4 (such as: the heat exchangers, steam turbine
or drive shafts) over Avista’s expected 20-year life of the plant?
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 19 of 1057
Other Colstrip Recommendations
•Develop a list of events regarding the economic viability of Colstrip
–For each event identify the cost, probability of occurrence, and cost range
•The 2019 plan should clearly and transparently
–Identify cost data and discuss in detail the relationship between the range of these input
assumptions, portfolio modeling logic, and the output of the modeling, as well as how the
Company used such analysis to choose its PRS.
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 20 of 1057
Conservation Potential Assessment
The 2019 IRP must include the following:
1.All conservation measures excluded from the CPA, including those excluded prior to
technical potential determination.
2.The rationale for excluding any measure.
3.A description, and source, of Unit Energy Savings data for each measure included in the
CPA.
4.An explanation for any differences in economic and achievable potential savings.
•The Company should also share its proposed energy efficiency measure lists with the
Conservation Advisory Group prior to completing the CPA.
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 21 of 1057
Demand Response and Advanced Metering
Infrastructure (AMI) Project
•The 2017 IRP does not consider the adoption of AMI technology in its energy
efficiency or demand response modeling, nor does it demonstrate any
potential benefits of deploying AMI.
•The Commission notes that the IRP is also one of the Company’s
opportunities to develop a record for the future demonstration of prudent
resource acquisition.
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 22 of 1057
Forecasted Price of Natural Gas
•The Commission does not expect utilities to predict future natural gas prices
with perfect accuracy, acknowledging this exercise is a forecast.
•We expect the utility to question and investigate the facts and reasoning used
by the consultants to derive their forecasts, given that past IRPs have
included a high-side bias to natural gas prices.
•Avista must ensure its natural gas price forecast represents the most
reasonable expectation of the future.
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 23 of 1057
Distribution System Upgrade Planning
•Any analysis of a distribution system upgrade should include consideration of storage
options that capture locational benefits associated with the site in question.
•The Commission encourages Avista’s use of sub-hourly models in the core IRP development
process to identify distribution system enhancements in its next IRP.
•Avista should perform a study to determine ancillary services valuation in the market and use
that value to evaluate the cost effectiveness of storage and peaking technologies using intra-
hour modeling capabilities.
•Advises Avista to model generic commercially available storage technologies within the IRP,
including consideration of efficiency rates, capital cost, operation and maintenance, life cycle
costs, and ability to provide non-power supply benefits.
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 24 of 1057
Other Comments and Recommendations
•Optimal Planning Reserve Margin
–The Commission urges Avista to monitor winter and summer resource adequacy and
continue to analyze planning margins, using its loss of load model, and continue to work
with the Council to validate and update its requirements while examining additional tools
such as Expected Loss of load and Expected Unserved Energy.
•Update Legacy Studies
–For future IRPs, citations to legacy analysis should be accompanied by a rationale for
why the study does not need to be updated.
•Portfolio Scenario Cost Comparison
–In displaying the costs and risks of a portfolio scenario in its IRP, Avista should
prominently display a comparison chart of the present value of revenue requirement of
each portfolio scenario along with its associated risk.
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 25 of 1057
Emissions Price Modeling and Cost Abatement Supply
Curve
•In future IRPs, Avista should incorporate in its preferred resource strategy the cost of risk of
future greenhouse gas regulation in addition to known regulations.
•This cost estimate should come from a comprehensive, peer-reviewed estimate of the
monetary cost of climate change damages, produced by a reputable organization.
•We suggest using the Interagency Working Group on Social Cost of Greenhouse Gases
estimate with a three percent discount rate.
•Avista should also continue to model other higher and lower cost estimates to understand
how the resource portfolio changes based on these costs.
•The Company must also develop a supply curve of emissions abatement measures in its
next IRP.
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 26 of 1057
Public Process
•Expect the Company to provide written responses to all Advisory
Committee questions submitted to the Company in writing,
•Provide minutes for each Advisory Committee meeting.
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 27 of 1057
Washington IRP Rulemaking
•The Washington Commission opened Docket No. U-161024 on September 2016 to
consider the following topics:
–Energy storage;
–Requests for proposals;
–Avoided costs;
–Transmission and distribution planning;
–Flexible resource modeling; and
–General procedural improvements.
•Work has been ongoing for this docket and the process is expected to wrap up
before the end of this year.
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 28 of 1057
Load and Economic Forecasts
Grant D. Forsyth, Ph.D.
Chief Economist
First Technical Advisory Committee Meeting
July 25, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 29 of 1057
Main Topic Areas
•Service Area Economy
•Peak Load Forecast
•Long-run Forecast
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 30 of 1057
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 31 of 1057
Distribution of Employment: Services and
Government are Dominant
Source: BEA and author’s calculations.4
Farm
1%
Private
Goods
13%
Private Services
71%
Federal, civilian
2% (10%)Military
1%(8%)
State
3%(21% Gov)
Local
9%(61% Gov)
Other
15%
WA-ID MSA Employment, 2016
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 32 of 1057
Non-Farm Employment Growth, 2009-2018
Source: BLS and author’s calculations.5
-6%
-4%
-2%
0%
2%
4%
6%
Ju
n
-
0
9
Se
p
-
0
9
De
c
-
0
9
Ma
r
-
1
0
Ju
n
-
1
0
Se
p
-
1
0
De
c
-
1
0
Ma
r
-
1
1
Ju
n
-
1
1
Se
p
-
1
1
De
c
-
1
1
Ma
r
-
1
2
Ju
n
-
1
2
Se
p
-
1
2
De
c
-
1
2
Ma
r
-
1
3
Ju
n
-
1
3
Se
p
-
1
3
De
c
-
1
3
Ma
r
-
1
4
Ju
n
-
1
4
Se
p
-
1
4
De
c
-
1
4
Ma
r
-
1
5
Ju
n
-
1
5
Se
p
-
1
5
De
c
-
1
5
Ma
r
-
1
6
Ju
n
-
1
6
Se
p
-
1
6
De
c
-
1
6
Ma
r
-
1
7
Ju
n
-
1
7
Se
p
-
1
7
De
c
-
1
7
Ma
r
-
1
8
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 Since June 2009
Avista WA-ID MSAs U.S.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 33 of 1057
Non-Farm Employment: Finally Catching Up
Source: BLS and author’s calculations.6
90
92
94
96
98
100
102
104
106
108
110
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
-
1
3
Ap
r
-
1
4
Au
g
-
1
4
De
c
-
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
No
n
-Fa
r
m

E
m
p
l
o
y
m
e
n
t

D
e
c

2
0
0
7
=
1
0
0
Non-Farm Employment Level Since 2007 (Dashed Shaded Box = Recession Period)
Avista WA-ID MSAs U.S.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 34 of 1057
Population Growth: Recovering with
Employment Growth
Source: BEA, U.S. Census, and author’s calculations.7
1.9%
1.4%
1.2%
0.8%
0.5%0.5%
0.8%
1.1%
1.3%
1.8%1.9%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
An
n
u
a
l

G
r
o
w
t
h
Population Growth in Avista WA-ID MSAs
Proxy for
Customer
Growth
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 35 of 1057
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 36 of 1057
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial
loads.
•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. The historical impacts of DSM
programs are “trended” into the forecast.
•The coefficients of the model are used to generate a distribution of peak loads
by month based on historical max/min temperatures, holding GDP constant.
An expected peak load can then be calculated for the current year (e.g., 2016).
Model confirms Avista is a winter peaking utility for the forecast period;
however, the summer peak is growing at a faster than the winter peak.
•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.
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 37 of 1057
GDP Growth Assumptions: 2015 IRP vs. 2017 IRP
10
2.6%
2.2%
2.0%
1.8%1.8%2.0%
2.3%
2.1%
2.1%2.1%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
2018 2019 2020 2021 2022 2023
An
n
u
a
l

G
r
o
w
t
h
2019 IRP GDP Growth 2017 IRP GDP Growth
Source: Various and author’s calculations.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 38 of 1057
Current Peak Load Forecasts for Winter and
Summer, 2018-2043
11
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
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
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2018-42
Winter 0.34%
Summer 0.36%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 39 of 1057
Current and Past Peak Load Forecasts for
Winter Peak, 2011-2043
12
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
Me
g
a
w
a
t
t
s
Winter Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 40 of 1057
Current and Past Peak Load Forecasts for
Summer Peak, 2011-2043
13
1,250
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
Me
g
a
w
a
t
t
s
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 41 of 1057
Long-Term Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 42 of 1057
Basic Forecast Approach
2019
Time
2024 20452025
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, and ARIMA error
correction.
5)Native load (energy) forecast derived from retail load forecast.
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 and
EV/PHEVs.
Medium Term Long Term
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 43 of 1057
The Long-Term Residential Relationship, 2020-
2040
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as
population growth, 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.
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 44 of 1057
0.40%
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
1.30%
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
Annual Residential Customer Growth Rates
2019 IRP Residential Customer Growth 2015 IRP Residential Customer Growth
2017 IRP Residential Customer Growth
Residential Customer Growth, 2019-2045
Medium Term Long Term
Average annual growth rate from
2019-2045 = 0.7%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 45 of 1057
18
Residential Solar Penetration, 2008-2017
0.00%
0.02%
0.04%
0.06%
0.08%
0.10%
0.12%
0.14%
0.16%
310,000 315,000 320,000 325,000 330,000 335,000 340,000
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
2008
2014
2015
2016
2017
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 46 of 1057
Residential Solar Penetration, 2019-2045
19
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
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
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental PV Customers
2017 IRP Base-Line Residential Solar Customers 2019 IRP Base-Line Residential Solar Customers
By 2045, penetration will be near 1.5% of
residential customers and average size of
installed systems will be 10,000+ watts.
Current penetration is 0.14% and typical
size is 7,800 watts.
Penetration was near 0.5% of
residential customers and average size
of installed systems was 6,000 watts.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 47 of 1057
Residential EVs/PHEVs, 2019-2045
20
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
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
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2017 IRP Projected EV/PHEV 2019 IRP Projected EV/PHEV
Current ≈ 700
Forecast By 2045 Prob.
Low 20,000 50%
Middle 70,000 30%
High 120,000 20%
Weighted Average 63,000
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 48 of 1057
Residential EVs/PHEVs by Household Income
21 Source: EIA, Today in Energy, May 2018. Regional data from U.S. Census
Spokane +
Kootenai
12%Spokane +
Kootenai
7%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 49 of 1057
EV/PHEV Gasoline CO2 Savings Avista
Service Territory
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
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
Estimated EV/PHEV Gasoline CO2 Reduction in Metric Tons
22
Estimated with DOE data. Assumes 5.18
metric tons of C02 per gasoline vehicle.
Savings = Number of EV/PHEV x 5.18
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 50 of 1057
Native Load Forecast, 2019-2045
950
1,000
1,050
1,100
1,150
1,200
1,250
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
Native Load Forecast, Average Megawatts
2019 IRP Base-Line Native Load 2015 IRP Base-Line Native Load 2017 IRP Base-Line Native Load
Medium Term Long Term
23
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 51 of 1057
Native Load Growth Forecast, 2019-2045
-0.1%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
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
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2019 IRP Base-Line Native Load Growth 2017 IRP Base-Line Native Load Growth
EV/PHEV “Bend”
24
IRP Avg. Annual
Growth
2019 IRP 0.40%
2017 IRP 0.51%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 52 of 1057
Residential UPC Growth: 2019-2045
25
-2.50%
-2.00%
-1.50%
-1.00%
-0.50%
0.00%
0.50%
1.00%
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
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth
2019 IRP Residential Base-Line UPC Growth
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 53 of 1057
Long-Term Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
26
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 54 of 1057
Monthly Conservation as a Share of Total
Actual Retail Load: Navigant Estimates
27
Ratio = 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑦𝑦𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑌𝑌
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
Ja
n
-
9
9
Ju
l
-
9
9
Ja
n
-
0
0
Ju
l
-
0
0
Ja
n
-
0
1
Ju
l
-
0
1
Ja
n
-
0
2
Ju
l
-
0
2
Ja
n
-
0
3
Ju
l
-
0
3
Ja
n
-
0
4
Ju
l
-
0
4
Ja
n
-
0
5
Ju
l
-
0
5
Ja
n
-
0
6
Ju
l
-
0
6
Ja
n
-
0
7
Ju
l
-
0
7
Ja
n
-
0
8
Ju
l
-
0
8
Ja
n
-
0
9
Ju
l
-
0
9
Ja
n
-
1
0
Ju
l
-
1
0
Ja
n
-
1
1
Ju
l
-
1
1
Ja
n
-
1
2
Ju
l
-
1
2
Ja
n
-
1
3
Ju
l
-
1
3
Ja
n
-
1
4
Ju
l
-
1
4
Ja
n
-
1
5
Ju
l
-
1
5
Ja
n
-
1
6
Ju
l
-
1
6
Ja
n
-
1
7
Ju
l
-
1
7
Ra
t
i
o

o
f

C
o
n
s
e
r
v
a
t
i
o
n

t
o

K
W
H

L
o
a
d

Energy Crisis
ARRA
Increased
Conservation
Activity
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 55 of 1057
Median Monthly Conservation as a Share of
Total Actual Retail Load: Navigant Estimates
28
Median Ratio Month t = Median𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸, excluding 2001
0.776%
0.670%
0.757%
0.685%0.707%
0.757%
0.815%
0.696%
0.639%
0.722%0.717%0.739%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Me
d
i
a
n

C
o
n
s
e
r
v
a
t
i
o
n

t
o

L
o
a
d

R
a
t
i
o
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 56 of 1057
Comparison of Native Load Forecasts, 2019-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
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
aM
W
aMW Load Comparision with Conservation
Base-Line Native Load Base-Line Native Load with Conservation Added Back29
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 57 of 1057
2017 IRP Action Plan Update
James Gall, IRP Manager
First Technical Advisory Committee Meeting
July 25, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 58 of 1057
Generation Resource Related Analysis
•Continue to review existing facilities for opportunities to upgrade capacity and efficiency.
–Avista is currently evaluating opportunities at Kettle Falls and Post Falls.
•Model specific commercially available storage technologies within the IRP; including efficiency rates,
capital cost, O&M, life cycle, and ability to provide non-power supply benefits.
–Avista will model a suite of storage options using third party data for cost and operating data. For
benefits, Avista will model both distribution and transmission level storage to quantify locational
benefits.
•Update the TAC regarding the EIM study and Avista plan of action.
–Update to be provided later this year.
•Monitor regional winter and summer resource adequacy, provide TAC with additional Avista LOLP
study analysis.
–LOLP/ELCC analysis is currently in process and will be presented at November meeting.
•Update the TAC regarding progress regarding Post Falls Hydroelectric Project redevelopment.
–Avista is evaluating multiple options at Post Falls, an update on the plan will be at the February
2019 meeting.
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 59 of 1057
Generation Resource Related Analysis
•Perform a study to determine ancillary services valuation for storage and peaking technologies using
intra hour modeling capabilities. Further, use this technology to estimate costs to integrate variable
resources.
–Avista plans on performing this study with the Avista’s ADSS model. At this time intra hour logic is
not available. If it is not available at the time of the IRP analysis, sensitivities analysis will be
performed to simulate this changes in reserve requirements.
•Monitor state and federal environmental policies effecting Avista’s generation fleet.
–Avista is continually monitoring policies that may impact the generation fleet.
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 60 of 1057
Energy Efficiency and Demand Response
•Determine whether or not to move the T&D benefits estimate to a forward looking value versus a
historical value.
–Avista is participating in the PNUCC and the NPCC investigation into a reasonable methodology to
determine T&D deferral values. Avista plans to use the preferred methodology from this effort. As of
now, the method is based on the utilization factor of expected capital spending on T&D projects.
•Determine if a study is necessary to estimate the potential and costs for a winter and a summer
residential demand response program and along with an update to the existing commercial and
industrial analysis.
–Avista has engaged AEG to conduct this study. The results will be shared at the March Meeting.
•Use the utility cost test methodology to select conservation potential for Idaho program options.
–Avista is still committed to this methodology
•Share proposed energy efficiency measure list with Advisory Groups prior to CPA completion.
–A list will be made available prior to the March meeting.
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 61 of 1057
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 is committed to this Action Item and actively engages in this area.
•Continue to participate in BPA transmission processes and rate proceedings to minimize costs of
integrating existing resources outside of Avista’s service area.
–Avista is committed to this Action Item and actively engages in this area.
•Continue to participate in regional and sub-regional efforts to facilitate long-term economic expansion
of the regional transmission system.
–Avista is committed to this Action Item and participates in these efforts.
•IRP and T&D planning will coordinate on evaluating opportunities for alternative technologies to solve
T&D constraints.
–Avista will model at least five locations for both transmission and distribution assets where the
system could alternatively be upgraded with a distributed energy resources (DER) rather than
traditional assets to test whether or not a coordinated DER is a lower cost to customers.
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 62 of 1057
Draft 2019 Electric IRP Work Plan
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
July 25, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 63 of 1057
Tentative TAC Meetings
•TAC 1 (July 25, 2018): TAC Meeting Expectations and IRP process overview,
review of 2017 IRP Commission acknowledgement letters and policy
statements, demand and economic forecast, draft 2019 Electric IRP Work
Plan, and Hydro One’s merger agreement’s impact on the 2019 IRP.
•November 2018: Modeling process overview, generation options (costs and
assumptions), resource adequacy and ELCC analysis, overview of home
heating technologies and efficiency, expected case key assumptions (regional
loads, CO2 regulation, etc…), and market and portfolio scenarios.
•February 2019:Natural gas price forecast, electric market forecast, IRP
transmission planning studies, distribution planning within the IRP, existing
resource overview –Colstrip, Lancaster and other resources, and final
resource needs assessment.
•March 2019: Ancillary services and intermittent generation analysis,
conservation and demand response potential assessment (AEG), Pullman
Smart Grid Demonstration Project review, draft Preferred Resource Strategy,
and draft market and portfolio results.
•April 2019: Review of final PRS, market scenario results, portfolio scenario
results, carbon cost abatement supply curves and 2019 Action Items.
22
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 64 of 1057
2019 Draft Electric IRP Timeline
Preferred Resource Strategy (PRS)Tasks Target Date
Finalize energy forecast July 2018
Identify Avista’s supply resource options September 2018
Begin Aurora market model development October 2018
Energy efficiency load shapes input into Aurora November 2018
Finalize data sets/statistics variables for risk studies November 2018
Transmission and Distribution studies due December 2018
Finalize natural gas price forecast December 2018
Communicate energy efficiency options to TAC December 2018
Finalize deterministic & stochastic expected case market studies January 2019
Due date for additional study requests January 15, 2019
Develop PRiSM model January 2019
Finalize peak load forecast February 2019
Finalize PRiSM model assumptions February 2019
Simulation of risk studies “futures” complete February 2019
Simulate market scenarios in Aurora February 2019
Evaluate resource strategies against market futures and scenarios March 2019
Present preliminary study and PRS to TAC March 2019
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 65 of 1057
2019 Draft Electric IRP Timeline
Writing Tasks Target Date
File 2019 IRP Work Plan August 31, 2018
Prepare report and appendix outline October 2018
Prepare text drafts April 2019
Prepare charts and tables April 2019
Internal drafts released at Avista May 2019
External draft released to the TAC May 31, 2019
TAC comments and edits due June 28, 2019
Final editing and printing August 2019
Final IRP submission to Commissions and distribution to TAC August 31, 2019
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 66 of 1057
2019 IRP Modeling Process
Preferred
Resource
StrategyAURORA
“Wholesale Electric Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Existing Resources
Resource Options
Transmission
Resource & Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
&RPS
Balances Generation/Storage
Options & Costs
T&D
Projects/Costs
Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
5
Demand Response
Measures/Costs
Environmental
Policy
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 67 of 1057
2019 Electric IRP Draft Outline
•Executive Summary
•Introduction and Stakeholder Involvement
•Economic and Load Forecast
–Economic Conditions
–Avista Energy and Peak Load Forecast
–Load Forecast Scenarios
•Existing Supply Resources
–Avista Resources
–Contractual Resources and Obligations
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 68 of 1057
2019 Electric IRP Draft Outline
•Energy Efficiency and Demand Response
–Conservation Potential Assessment
–Demand Response Opportunities
•Long-Term Position
–Reliability Planning and Reserve Margins
–Resource Requirements
–Reserves and Flexibility Assessment
•Policy Considerations
–Environmental Concerns
–Greenhouse Gas Issues
–State and Federal Policies
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 69 of 1057
2019 Electric IRP Draft Outline
•Transmission & Distribution Planning
–Avista’s Transmission System
–Future Upgrades and Interconnections
–Transmission Construction Costs and Integration
–Transmission and Distribution Efficiencies
•Generation Resource Options
–New Resource Options
–Avista Plant Upgrades
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 70 of 1057
2019 Electric IRP Draft Outline
•Market Analysis
–Marketplace
–Fuel Price Forecasts
–Market Price Forecast
–Scenario Analysis
•Preferred Resource Strategy
–Resource Selection Process
–2017 Preferred Resource Strategy
–Efficient Frontier Analysis
–Avoided Cost
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 71 of 1057
2019 Electric IRP Draft Outline
•Portfolio Scenarios
–Portfolio Scenarios
–Tipping Point Analyses
•Action Plan
–2017 Action Plan Summary
–2019 Action Plan
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 72 of 1057
Hydro One Merger Agreements Related to Resource
Planning
James Gall, IRP Manager
First Technical Advisory Committee Meeting
July 25, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 73 of 1057
Avista’s Proposed Merger with Hydro One
•Regulatory process update:
•Announced proposed merger July 2017
•Applications for approval filed in September 2017
•Federal approvals received
•Approvals from Alaska and Montana received
•Settlement agreements reached and filed in Washington, Idaho and Oregon.
Approvals are still pending in these states.
•We continue to work through the regulatory process toward approval
More information at www.myavista.com/hydroone
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 74 of 1057
Presentation Objective
•This presentation will review agreements between Avista, Hydro One
and intervening parties related to the Electric IRP per the merger
agreements in Washington & Idaho.
•These agreements will include methodology and specific goals the next
IRP shall include if the merger is approved.
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 75 of 1057
WA #52 Renewable Portfolio Standard Requirements
Hydro One acknowledges Avista’s obligations under applicable
renewable portfolio standards, and Avista will continue to comply with
such obligations.
Avista will acquire all renewable energy resources required by law and
such other renewable energy resources as may from time to time be
deemed advisable in accordance with Avista’s integrated resource
planning (“IRP”) process and applicable regulations.
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 76 of 1057
WA #53 Renewable Energy Resources
Avista’s non-fossil fueled generation resources constitute more than 50% of its
generation portfolio, and Avista exceeds the renewable energy standards
currently applicable to the company under RCW 19.285.040(2).
Avista makes the following renewable energy commitments. Both commitments
are made only to the extent resources are reasonably commercially available
and are (1) necessary to meet load and (2) consistent with the lowest
reasonable cost resource portfolio pursuant to Avista’s established IRP and
pursuant to the Commission’s resource evaluation and acquisition rules and
policies.
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 77 of 1057
WA #53 (a) Renewable Energy Resources
Avista will commit to initiating a Request for Proposal with the intent of acquiring
additional eligible renewable energy resources as part of this process above
and beyond the current renewable energy standards in law. Avista will commit
to obtain approximately 50 aMW of expected energy from new eligible
renewable resources by 2022.
The aMW obtained under this commitment may be used to satisfy any increase
that may be caused by changes to the renewable energy standards in law after
the date an Order approving this merger has been entered.
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 78 of 1057
ID #52: Renewable Energy Resources
Avista will continue to offer renewable power programs in consultation with
stakeholders.
Communications with customers shall accurately reflect the environmental attributes
associated with power delivered to such customers. Hydro One and Avista
acknowledge that Avista retains the burden of proof to demonstrate the prudence of
any resource acquisition.
Nothing in this Commitment prohibits Avista from selling renewable energy credits that
arise from resources included in base rates applicable in Idaho. Hydro One
acknowledges Avista's obligations under applicable renewable portfolio standards, and
Avista will continue to comply with such obligations.
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 79 of 1057
RFP Schedule
•June 6, 2018 –RFP Issuance
•June 20, 2018 –Preliminary Information due (CLOSED)
•June 29, 2018 –Short list identified
•July 20, 2018 –Detailed Proposals due from short-listed bidders
(Exhibit C)
•July 23, 2018 through August 15, 2018 –Negotiations with short-
bidders
•August 29, 2018 –Final bidder(s) selected
•November 2, 2018 -Final contracting complete with successful
bidder(s)
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 80 of 1057
RFP Bid Summary
•Nearly 900 aMW from 48 bids
•Proposals included wind, solar, geothermal, fuel cells, and storage
•From Washington, Idaho, Montana, Oregon, and Nevada
•Both PPA’s and build to own transfers were received
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 81 of 1057
WA #53 (b) Renewable Energy Resources
Avista will commit to obtain at least 90 aMW of expected energy from
new eligible renewables resources to become operational approximately
within a year of the timeframe that Colstrip 3 and 4 go offline.
“Resources” is understood to include Power Purchase Agreements (“PPAs”). Nothing in either commitment prohibits
Avista from retaining or selling renewable energy credits associated with such resources that are surplus to Avista’s
needs to meet Washington Renewable Portfolio Standards targets.
Communications with customers shall accurately reflect the environmental attributes associated with power delivered to
such customers. Hydro One and Avista acknowledge that Avista retains the burden of proof to demonstrate the
prudence of any resource acquisition.
The utility should work with an independent third-party consultant, with expertise in renewable energy resources, to
ensure that the utility has up-to-date resource cost and performance assumptions, as well as the appropriate learning
curves.
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 82 of 1057
WA #54 & ID #56 Greenhouse Gas and Carbon
Initiatives
Hydro One acknowledges Avista’s Greenhouse Gas and Carbon
Initiatives contained in its current Integrated Resource Plan, and
Avista will continue to work with interested parties on such
initiatives.
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 83 of 1057
WA #57 Energy Efficiency Goals and Objectives
Hydro One acknowledges Avista’s energy efficiency goals and
objectives set forth in Avista’s 2017 Integrated Resource Plan and
other plans, and Avista will continue its ongoing collaborative efforts
to expand and enhance them.
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 84 of 1057
ID #53 Regulatory IRP Sideboards
Avista and its affiliates agree to consider in all resource planning and acquisition efforts both demand-side
and renewable energy resources that are consistent with the Idaho Commission's resource evaluation and
acquisition rules and policies.
•Avista and its affiliates agree that "Resources" to be considered in all IRPs include Power Purchase
Agreements ("PPAs").
•Avista commits to calculating a variable generation resource's contribution to capacity in terms of that
resource's contribution to resource adequacy and that resource's ability to reduce the loss of load
probability in some or all hours or days utilizing the Effective Load Carrying Capability ("ELCC")
methodology or an appropriate approximation.[WA #60]
•Avista will work with an independent third-party consultant, with expertise in renewable energy
resources, to ensure that the utility has up-to-date resource cost and performance assumptions, as well
as the appropriate learning curves, for use in the 2019 IRP process.
•Unless it conflicts with any instructions contained in the Commission's acknowledgement letter in
response to Avista's current integrated resource plan (IRP), beginning with the next IRP, Avista commits
to modeling a range of potential costs for greenhouse gas emissions, and will work with its IRP
Advisory Group to determine the appropriate values to model. [WA #55]
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 85 of 1057
WA #76 & ID #69 Colstrip Depreciation
Hydro One and Avista agree to a depreciation schedule for Colstrip
Units 3 and 4 that assumes a remaining useful life of those units
through December 31, 2027.
WA: See Attachment A to Appendix A (Master List of Commitments in Washington) to the
Settlement Stipulation, “Colstrip Commitment Summary and Description”
ID: See #69 for full description of commitment14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 86 of 1057
Other “IRP” Related Items
WA #58: Optional renewable power program
WA #59 & ID #54: Energy Imbalance Market (“EIM”)
WA #61: Industrial customers’ self direct conservation
WA #62 & ID #55: Transport electrification
WA #63: Professional home energy audit
WA #65 & ID #58: Low-income energy efficiency funding
WA #67: Funding for low-income participation in new renewables
WA #69: Replacement of manufactured homes
WA #70: Low-income weatherization
ID #59 & #60: Industrial load DSM assistance
ID #71: Colstrip transmission planning
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 87 of 1057
Attendees: TAC 1, July 25, 2018 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Kirsten Wilson, Washington State DES; Amy Wheeless, NW
Energy Coalition; David Nightingale, Washington UTC; Doug Howell, Sierra Club; Kathlyn Kinney, Biomethane; Grant Forsyth, Avista; Jorgen Rasmussen, Solar Acres Farm; John Barber, Rockwood Retirement Communities; Gerry Snow, PERA; Dean Kinzer, Whitman County Commission; Garret Brown, Avista; Scott Kinney, Avista; Yao Yin, IPUC; Ben Serrurier, Cyprus Creek Renewables; Terrence Browne, Avista; Jason
Thackston, Avista; Darrell Soyars, Avista; Kim Vollan, Avista; Kevin Davis, IEP; Matt Nykiel, ICL; Ryan Finesilver, Avista; Paul Kimmel, Avista; and John Osborne, MD.
Phone:
Kelly Hall, Climate Solutions; Mike Starrett, NPCC; Steve Johnson, Washington UTC;
Ian Bledsoe; Energy Consultant, NW Energy Coalition
These notes follow the progression of the meeting. They include summaries of the
questions and comments from those not presenting, the responses (in italics), as well
as significant points raised by the presenters that are not shown on the slides
TAC Expectations and Process Overview, John Lyons
Presentation covering the background behind the electric IRP, TAC member
involvement, review agenda for the day and expectations from Avista and from the TAC.
• Jorgen Rasmussen: Can we have someone come in and talk about energy
security? Yes, Avista will look into adding this as a topic.
• Amy Wheeless: Request to track all questions, requests and responses.
• Matt Nykiel: Asked about getting assumptions earlier in the process to be able to
understand them better and make comments. Yes, Avista will work on this and
many of the assumptions will be made available at the next meeting in
November 2019.
• Amy Wheeless: How do we discuss the assumptions? The TAC gets the slides
with the assumptions ahead of the meetings.
• Doug Howell: Would like to see the slides three days ahead of the meetings.
Slides will go out on Friday before the Tuesday or Wednesday meetings.
• Matt Nykiel: Concerns about slide #3 and limitations to the discussions and
questions asked. The points are in the slides to make sure we can get through
the agenda for each TAC meeting.
• Amy Wheeless: We want an open exchange of ideas. Request that participants
can provide data and Avista will consider using it. It is best if the data is
publically available.
• David Nightingale: Discussion on minutes of the TAC and how they will be made
available. Avista is still working on the logistics of this, possibly by email or even
posted on the web site.
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Schedule 1a, Page 88 of 1057
• Gerry Snow: Is there a continuing forum between meetings? Can Google Docs
be used? There isn’t an ongoing forum or discussion group, but the IRP is
available by email and phone for any questions, comments and concerns.
Information can then be passed on to the whole TAC. No, IT policy doesn’t allow
us to use Google Docs, but could explore the use of One Drive if email doesn’t
work for TAC members.
• Clint Kalich: Discuss how the Avista web site is used in conjunction with the IRP.
Showed the TAC where to find the IRP section of the web site and the
documents available there.
2017 IRP Acknowledgements & Policies, James Gall
Presentation covering the expectations and comments in the acknowledgment letters
received from the Idaho and Washington Commissions for the 2017 Electric IRP.
• Doug Howell: Passed around letter dated June 26, 2018 to the Idaho, Montana,
Oregon and Washington utility commissions concerning Westmoreland Coal
Company; handout titled “Fracked Gas The Next Big Climate Fight;” and a July
24, 2018 article from The Billings Gazette concerning the Colstrip outage.
• Doug Howell: Wants more details on the assumptions for air quality controls at
Colstrip.
• Steve Johnson: Comment about sheltering or excluding anyone involved in
negotiations for a new contract or purchase of the Lancaster facility from non-
public analysis to ensure they are arm’s length from any new transaction.
• Doug Howell: Colstrip remediation and decommissioning and how it is going to
be paid for in a way that provides intergenerational equity.
• Doug Howell: How are existing capital projects used for supporting investment in
the IRP, Colstrip capital? This is a resource decision that uses the IRP
developed avoided cost to analyze new projects.
• Steve Johnson replied that unsure if the IRP is the place to describe how much
and when money is to be recovered for Colstrip. The Company would
demonstrate prudence in a future rate proceeding, not jumping ahead in an IRP
to design a cost recovery mechanism. The IRP recognizes such costs to be
included in depreciation recovery. IRP should identify all risks for Colstrip Units 3
and 4 and potential costs in response to the acknowledgment letter from the
Washington UTC.
• Matt Nykiel: Wants the group to be kept informed on whether a decision has
been made on depreciation at Colstrip.
• Steve Johnson offered to have a more detailed meeting with the public about
rate making.
• Dave Nightingale: Anticipation of a resource becoming unavailable if
uneconomic. Identify resources that are at risk of going away.
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Schedule 1a, Page 89 of 1057
• Matt Nykiel: Will the November meeting discuss regional coal policies from
Portland General Electric and PacifiCorp in Oregon? Yes, regional coal policies
will be covered in a later meeting.
• Doug Howell: Wants to include the risk associated with the growing liabilities of
upstream natural gas leakages. Avista has not historically considered
externalities beyond those required by laws or regulations, but will take this
request into consideration.
• Doug Howell: The Sierra Club wants the inputs for Aurora so they can have a
consultant review them and run the models. This will require a discussion at
Avista to determine what data could be shared and how it could be shared.
• Matt Nykiel: Concerns with how we can discuss the inputs without having all of
the data.
• Ben Serrurier: Do the consultants provide the data that supports how they
derived their natural gas price forecasts and can that be shared with the TAC?
Yes, Avista can provide what we are allowed to. Probably cannot give specific
details, but should be able to share the main driving forces behind the gas price
forecasts.
• Yao Yin: What if there are big differences between the two consultants for the
gas price forecasts if there are conflicting or different assumptions? Avista has
blended these forecasts in the past and has not seen fundamentally different
forecasts. Any major differences would probably be due to conflicting
assumptions.
• Dave Nightingale: Will there be high, low and medium cases? Avista does an
expected case with stochastics with an average of the 500 futures as the
expected case. Ask the consultant to do a high and low forecast. Avista will
check into this with the consultants, but it may be too costly.
• James Gall: Should we include some more information here about distributed
generation and energy storage? Yes and storage will be included as a new
resource option.
• Amy Wheeless: More distributed resources and non-traditional. Yes, Avista will
include more options and will need to see how far we can take this.
• Ben Serrurier: How are you choosing the five projects for distribution upgrades?
The amounts were small enough that we asked that group for five. UTC
threshold, but we are looking at needs and what could be met by a distributed
energy resource to solve constraints in the IRP timeframe.
• Kirsten Wilson: Regarding Washington Executive Order 1801, is vehicle-to-grid
storage going to be included? Washington State University may have to follow
the rules identified in the Executive Order. Avista will try to incorporate this, but
really has no control over this type of resource. Vehicle-to-grid storage may end
up being a scenario.
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Schedule 1a, Page 90 of 1057
• Steve Johnson: Offline, examine paragraph 43 of the UTC policy on storage
framework or method. Is this practical or is there a better way of doing it?
Criticism has been leveled at this method. Avista will probably do this in PRiSM.
• Doug Howell: For carbon prices, include the implications of the upstream
emissions.
• Dave Nightingale: Regarding how to share meeting minutes, they usually get
approved at the next meeting. Avista still needs to decide on the best way to
share the meeting minutes with the TAC.
• Dave Nightingale: The second and third bullets (WUTC IRP Rulemaking about
requests for proposals and avoided costs) are being handled separately as two
rulemakings under separate dockets. On a parallel track with conservation
(under the Advisory Group) with a subgroup for distribution planning. This is still
in discussions and a new draft will be ready in the next month or so. It will be
done by the end of the year, but will be surprised if the new regulations get
applied to this IRP.
• Yao Yin: Third point, avoided cost, trying to unwind: PURPA, resource
differences, and improved rule on how to use it. Idaho has a SAR (surrogate
avoided resource) and IRP method. Larger and smaller resource methods,
maybe we should talk offline about these.
• Doug Howell: Suggest using the Washington Governor’s Deep De-carbonization
Study to get assumptions on EV, building codes, solar and others. Avista will run
a scenario with higher assumptions.
Break (back at 10:55)
Demand and Economic Forecast, Grant Forsyth
• Grant Forsyth: Employment is one of the big drivers for customer growth, 71% of
the local economy is service based.
• Clint Kalich: Does local government include schools? Yes, it is the biggest share
and includes faculty, teachers and administrators.
• Grant Forsyth: Fairchild Air Force Base is going to be accepting all of the older
KC135 tankers as the new tankers are deployed elsewhere, so there will be a
buildup at Fairchild.
• Grant Forsyth: Idaho is growing faster than Washington service territory in
employment and population. The MSA (Metropolitan Statistical Area) is a well-
defined urban area with over 50,000 people.
• Dave Nightingale: Why is non-farming used? Farming is so low for employment it
does not make a huge difference. It is much bigger for income.
• Grant Forsyth: In-migration is the key driver for customer growth
• Grant Forsyth: Population growth is a strong proxy for customer growth.
• Garrett Brown: What is the impact of the recent announcement by Amazon?
[Warehouse in Airway Heights with 1,500 expected employees] Not a large direct
impact because they will be an Inland Power Customer, but Avista will serve their
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 91 of 1057
natural gas needs and will benefit from in-migration with some amount of
household and ancillary business growth.
• Doug Howell: Which are excluded to run the regression [in the peak load
forecast]? Excludes Clearwater and IEP (Inland Empire Paper) and then adds
them back in.
• Kathlyn Kinney: Why is the summer peak growing faster? It is a combination of
weather changes (why we moved from 30 to 20-year weather data); increased air
conditioning load because of higher incomes and lower costs for air conditioners;
winter conservation; and fuel switching from electric to natural gas.
• Grant Forsyth: There is a less strong impact from GDP on loads than in the past.
• Dave Nightingale: Graphically look at this, do these make sense based on the
past.
• Dave Nightingale: Are these GDP numbers regional? No, they are national GDP
estimates because our region follows the national numbers closely and regional
forecasts are scarce.
• Yao Yin: Questions about GDP differences in slide 11 (Current Peak Load
Forecasts for winter and summer, 2018-2043). Yes, they are different for each
year for 5 to 6 years, then extended out for the rest of the forecast.
• James Gall: Peak demand – we are planning to serve this load over the next 20
years plus a 14% peak planning margin and operating reserves. This made us
short in 2027 in the last plan. We may make adjustments as we get more data.
• Amy Wheeless: How does 14% compare to others? 11 – 17%. Depends on what
is included. We add operating reserves putting us at 21-22%, NPPC is about
23%. Water based utilities usually have higher planning margins for running out
of water. There is a chart on this in the last two IRPs.
• Yao Yin: Is PM necessary? Yes, we were able to cover the 2009 extreme cold
event.
• Matt Nykiel: Actual vs. forecast, do you have a chart? No, but James Gall looks
at the forecast vs. the actual after every event. We are not sure if we could add
this.
Long-term load forecast section
• Doug Howell: Is the 20-year data capturing the warming shift? It varies within our
service territory based on the work done by NASA. There is more of a warming
shift in Medford than Washington. The data shows the shift has somewhat
stabilized in the 20-year period.
• Amy Wheeless: UW climate impact and SnoPUD have data on this.
• Matt Nykiel: How do you pick the forward climate model? Can we use an average
like GDP? Potentially, we can verify GDP with historic data, but climate data may
be tough to correlate because it is lumpy, not uniform.
• Steve Johnson: Currently, is Avista’s view that the risk of climate change is open
ended? Yes, to the extent we can’t quantify it.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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• Clint Kalich: Magnitude of temperature and could also run scenarios on other
changes with similar results. Put a statement about risk and what we are
thinking.
• Yao Yin: Why not an econometric model for the long term? We could, but would
also need a population growth forecast.
• Garrett Brown: Is it positive or negative growth? Still positive, but about half
percent long term. 5% or more solar penetration starts making a difference.
More aggressive solar growth with larger projects over 10,000 watts.
• Yao Yin: Relationship between load and solar. How much is solar taking off of
load, the net impact?
• Doug Howell: What about the Commerce predictions for electric vehicles
(Executive Order 18-01)? Have not been able to determine where they got their
goals from, maybe the Governor’s deep de-carbonization pathway. We are going
to run some scenarios on different levels of electric vehicles, solar and
electrification.
• Amy Wheeless: Are electric vehicle fleets growing faster? In the model, there is a
connection to residential and commercial loads.
• David Nightingale: Distribution of model by Washington EVs (electric vehicles)
may be shifting with new models. Income and household density are the drivers
for EVs. Density is 4 times less in Spokane, so people live far enough away to
have some range anxiety.
• Jorgen Rasmussen: Also need to consider the used EV market and the number
and location of chargers. There are fewer chargers in our service territory.
• Jorgen Rasmussen: Could also consider the consumption of refineries. How far
do we take this?
• Yao Yin: Why not include solar in the resource side? This is for customer-owned
solar.
• Gerry Snow: When will we see the “duck curve”? Partly by feeder. 5% and higher
penetration will affect us for solar. This is more on an issue with Power Supply.
The location of the solar is important.
• Doug Howell: It would be useful if we could see growth rates and efficiency in a
deep de-carbonization scenario and how this overlays with the economic
forecast. Would need to see what kind of specific data we could get for this.
• David Nightingale: Electric vehicles are not utility scale, but impact Avista’s
system. Reliable, planning level at what point for electric vehicles and solar?
Summer peaks maybe.
• Doug Howell: When are the peaks? 6 pm in the summer and 7 – 8 am / 5 – 6 pm
in the winter.
• Kathlyn Kinney: Energy storage with hydrogen could change this.
• Yao Yin: (Slide 29 Median Monthly Conservation as a Share of Total Actual
Retail Load: Navigant Estimates): Have the ratios for the Navigant coefficients stayed the same? They have increased a bit, but not very much since using the
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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median rather than the average. The conservation estimate is from the DSM
area.
• Jorgen Rasmussen: Have there been more energy savings in the LEDs vs. the
conversions to natural gas? Yes, the LED lighting conversions are about double
the energy savings for lighting. Conversions to LED provide more savings than
fuel conversions on a per kWh basis.
• Amy Wheeless: The WUTC is wanting less fuel conversions.
• On the last slide, the blue line is the starting point for conservation selection
Lunch 12:00
2017 Action Plan Updates, James Gall
• Amy Wheeless: Are we presenting data on bullet 1, page 4. Yes, we will present.
Yes, publically.
• Doug Howell: List of BPA commitments with Governor Bullock’s (Montana)
process. Scott Kinney replied that we have done most of them and the rest are
up to BPA.
2019 IRP Draft Work Plan, John Lyons
• Dave Nightingale: Consider placing a draft IRP review place holder meeting at
the end.
• Gerry Snow: Are you considering additional storage instead of new resources?
Yes.
• Doug Howell: There is an expectation of signing a non-disclosure agreement to
be able to get the inputs used for the March and April meetings. We want to set
up a process to the data? Avista will need to meet internally and discuss this.
• Matt Nykiel: Timing of the November meeting, add time to the agenda to follow
up on assumptions.
• Amy Wheeless: Can Avista be more nimble for inputs to be shared regarding
CO2? We are going to try, but there are several moving parts with the election
and potential upcoming state legislative efforts in Washington.
• Doug Howell: How are you going to decide how to implement the social cost of
carbon and the citizen’s initiative (I-1631 carbon fee)? Avista is still determining
how to do this and waiting for the results of the November election.
• Jorgen Rasmussen: Remember the initiative (I-1631) is considered a fee instead
of a tax. Yes, it is modeled the same as a tax even though it’s a fee and the
recent state court ruling upheld I-1631 as a fee instead of a tax.
• Scott Kinney: Would like to add that there may be limits to the amount of studies
that can be run based on how many requests we receive.
Break
Hydro One Merger Agreements, James Gall
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• Jason Thackston: Avista is accelerating the depreciation for Colstrip as part of
the Hydro One agreement in Washington and only if the transaction is approved
in all five states and is consummated. Idaho has a separate depreciation study
case.
• Mike Starrett (phone): For the RFP short-list (for new, renewable generation), are
they below cost? Avista cannot share the specific cost information, but we are
getting current pricing data on renewable generation.
• Doug Howell: Would like to acknowledge the $4.5 million commitment to the City
of Colstrip by Hydro One.
Adjourn
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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2019 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Tuesday, November 27, 2018 Conference Room 130
Topic Time Staff
Introductions and TAC 1 Recap 9:30 Lyons

Modeling Process Overview 9:40 Gall Generation Resource Options 10:10 Gall Break 11:00
Home Heating Technologies Overview 11:15 Lienhard

Lunch 12:00

Resource Adequacy and Effective Load 1:00 Gall
Carrying Capability
Electric IRP Key Assumptions 1:45 Gall/Lyons Break 2:30 2019 IRP Futures and Scenarios 2:45 Gall/Lyons

Adjourn 3:30
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 96 of 1057
2019 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next two 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
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 in all or some of the process
•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 studies we can do
–The earlier study requests are made, the more accommodating we can be
–January 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3
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TAC #1 Recap –July 25, 2018
•Introduction
•TAC Expectations and Process Overview
•2017 IRP Acknowledgments and Policies
•Avista’s Demand and Economic Forecast
•2017 Action Plan Updates
•2019 IRP Draft Work Plan
•Hydro One Merger Agreements
•Meeting minutes are available on the IRP web site at
https://www.myavista.com/about-us/our-
company/integrated-resource-planning
4
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Today’s Agenda
•9:30 –Introductions and TAC 1 Recap, Lyons
•9:40 –Modeling Process Overview, Gall
•10:15 –Generation Resource Options, Gall
•11:00 –Break
•11:15 –Home Heating Technologies Overview, Lienhard
•12:00 –Lunch
•1:00 –Resource Adequacy and Effective Load Carrying
Capability, Gall
•1:45 –Key Assumptions, Gall and Lyons
•2:30 – Break
•2:45 –Futures and Scenarios, Gall and Lyons
•3:30 –Adjourn
5
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TAC 3 Topics
•TAC 3 on Wednesday, February 6, 2019
•Natural Gas Price Forecast
•Electric Market Forecast
•IRP Transmission Planning Studies
•Distribution Planning within the IRP
•Existing Resource Overview (Colstrip,
Lancaster, and other resources)
•Final Resource Needs Assessment
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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2019 IRP Modeling Process Overview
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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IRP Modeling Process
•The purpose of this discussion is to help you
understand the steps and process associated
with the analysis of the IRP.
•This presentation outlines the steps to develop
the plan along with a high level discussion of
how the tools and methods are used.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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2019 IRP Modeling Process
Resource
StrategyAURORA
“Wholesale Electric Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Existing Resources
Resource Options
Transmission
Resource & Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,Capacity,&RPS BalancesResource Adequacy Generation/Storage
Options & Costs
T&D
Projects/Costs
Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided
Costs
3
Demand Response
Measures/Costs
Environmental
Policy
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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•3rd party software-EPIS, Inc./Energy Exemplar
•Electric market fundamentals-production cost model
•Simulates generation dispatch to meet load and allows
for system constraints
Electric Market Modeling
4
Outputs:
–Market prices
–Energy mix
–Transmission usage
–Emissions
–Power plant margins,
generation levels, fuel costs
–Avista’s variable power supply
costs
Inputs:
–Regional loads*
–Fuel prices*
–Fuel availability*
–Resources (availability*)
–New resources costs
–Transmission
*Stochastic input
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 106 of 1057
Aurora Modeling Changes from 2017 IRP
•Use Epis/Energy Exemplar latest database vs.
Avista’s proprietary database
•Updates to the Epis database will include:
•Avista specific characteristics (load/generation/fuel)
•Fuel prices
•Regional hydro conditions (80-year record)
•Adjustments to allow market prices to go negative
•Load shape changes (electric vehicles/rooftop solar)
•Known regional resource retirements
•Split Northwest area between WA, OR, and ID (TBD)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 107 of 1057
Aurora Load Area Topology
Potential split by
state due to
environmental
policies
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 108 of 1057
Stochastic vs. Deterministic Analysis
•Deterministic analysis forecasts for a specific set of
inputs.
–Easy 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
Deterministic
Stochastic7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 109 of 1057
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
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 110 of 1057
PRiSM
Find optimal resource strategy to meet resource deficits over
planning horizon
New for the plan: Split Avista’s resources and loads
–City of Spokane
–Idaho
–Washington
Model selects its resources to reduce cost, risk, or both.
Objective Function:
–Minimize: Total Power Supply Cost on NPV basis (2020-2058)
–Focus on first 20 years of the forecast
–Subject to:
•Risk level•Capacity need +/-deviation•Energy need +/-deviation•Renewable portfolio standards•Resource limitations, sizes, and timing
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 111 of 1057
Efficient Frontier Concept
•Does not find the optimal portfolio, only the optimal
portfolio for a given level of risk.
•Used in investment finance for portfolio management.
Return
Ri
s
k
Equities
Bonds
Government Debt
Stock vs. Bond Example
Efficient Frontier
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 112 of 1057
Efficient Frontier
Demonstrates the trade off of cost and risk
Avoided Cost Calculation
Ri
s
k
Least Cost Portfolio
Least Risk Portfolio
Find least cost
portfolio at a given
level of risk
Short-Term Market
Market + Capacity + RPS = Avoided Cost
Capacity Need
+ Risk
Cost
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 113 of 1057
2019 Electric IRP
Generation Resource Options
James Gall,
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 114 of 1057
Overview & Considerations
•The assumptions discussed are “today’s” estimates and will likely have
periodic revisions.
•Resource costs vary depending on location, equipment, fuel prices, and
ownership; while IRPs use point estimates, actual costs will be different.
•Avista retained Black & Veatch to review the renewable and storage
resource assumptions as part of the Hydro One merger agreement.
•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 used “today” will be revised with the “final” assumption in
January 2019.
•An Excel file will be distributed with all resources, assumptions and cost
calculations for TAC members to review and provide feedback.
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 115 of 1057
Proposed Natural Gas Resource Options
Peakers
•Simple Cycle Combustion Turbine (CT)
–Aero and frame units
–Smaller units 44 MW to 80 MW
–Larger units up to 245 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 options 158 MW to 308
MW (3x2, 1x1)
–Larger options 324 MW to 480
MW (1x1)
•Large 2x1 technology not modeled
Natural gas turbines are modeled using a 30-year life with Avista ownership
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 116 of 1057
Renewable Resource Options
All Purchase Power Agreement (PPA) Options
Wind
•On-system wind (101 MW)
•Off-system wind (101 MW)
•Montana wind (101 MW)
•Off shore 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
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 117 of 1057
Other “Clean” Resource Options
•Geothermal (20 MW)
–Off-system PPA
•Biomass (100 MW)
–i.e. Kettle Falls 3
•Nuclear (100 MW)
–Off-system PPA share of a larger facility
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 118 of 1057
Storage Technologies
Lithium-Ion
•Assumes: 88% round trip efficiency (RTE),
10-year operating life
•Assumes Avista ownership
•5 MW Distribution Level
–4 hours (20 MWh)
–8 hours (40 MWh)
•25 MW Transmission Level
–4 hours (100 MWh)
–8 hours (200 MWh)
–16 hours (400 MWh)
–40 hours (1,000 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 Hydrogen Fuel Cell (varies)
–4 hours (100 MWh)
–16 hours (200 MWh)
–40 hours (1,000 MWh)
•25 MW Liquid Air (65% RTE)
•Liquid Air (retrofit natural gas CT)
–12.7 MW (59 MWh)
–78 MW (700 MWh)
•100 MW Pumped Hydro
–Share of larger project
–16 hours of storage
–PPA assumption
Updates to storage
costs are likely as
additional information
becomes available
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 119 of 1057
Resource Upgrades
•Northeast [natural gas peaker]
–7.5 MW using water injection
•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
•Post Falls Redevelopment [hydroelectric]
–8 MW, 4.5 aMW with larger modern units
•Long Lake 2nd Powerhouse [hydroelectric]
–68 MW, 12 aMW with additional powerhouse located at the current “cutoff” dam
•Monroe Street/Upper Falls [hydroelectric]
–80 MW, 27 aMW with additional powerhouse located in Huntington Park
•Cabinet Gorge [hydroelectric]
–110 MW, 18 aMW using the “bypass” tunnels to capture runoff spill
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 120 of 1057
Natural Gas Fixed & Variable Costs
Green: Reciprocating Engines
Blue: SCCT
Red: CCCT
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 121 of 1057
PPA Resource Cost Analysis
2040
2030
2020
9 Prices include utility loading such as variability integration and revenue taxes Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 122 of 1057
Storage Costs
Capacity based cost analysis
10
$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600
Distribution Scale 4hr Lithium-Ion
Distribution Scale 8hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
40hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Hydrogen Fuel Cell with 4 hrs storage w/ Electrolysis
Hydrogen Fuel Cell with 16 hrs Storage w/ Electrolysis
Hydrogen Fuel Cell with 40 Hrs Storage w/ Electrolysis
Liquid Air
Liquid Air (Retrofit CT)
Liquid Air (Retrofit- KFCT)
Pumped Hydro (16 hr/ 100 MW share)
$ per kW-Year
2040
2030
2020
Analysis still being performed
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 123 of 1057
Storage Costs
Energy based cost analysis
11
$0 $50 $100 $150 $200 $250 $300
Distribution Scale 4hr Lithium-Ion
Distribution Scale 8hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
40hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Hydrogen Fuel Cell with 4 hrs storage w/ Electrolysis
Hydrogen Fuel Cell with 16 hrs Storage w/ Electrolysis
Hydrogen Fuel Cell with 40 Hrs Storage w/ Electrolysis
Liquid Air
Liquid Air (Retrofit CT)
Liquid Air (Retrofit- KFCT)
Pumped Hydro (16 hr/ 100 MW share)
$ per kWh- Yr
2040
2030
2020
Analysis still being performed
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 124 of 1057
Facility Upgrade Cost Analysis
Green: Biomass
Blue: Hydro
Red: Natural Gas
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 125 of 1057
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 Dialog
contracts expire
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 126 of 1057
Review Excel Sheet
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 127 of 1057
Home Heating Technologies Overview
Tom Lienhard, Chief Energy Efficiency Engineer
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 128 of 1057
Home Heating Systems
•Delivery method
–Radiation
–Convection
–Forced Convection
•Number of controlled heating segments
•Fuel used for heating the fluid
–Electricity
–Natural Gas
–Other
•Efficiency of fuel delivery
•Heating load of the residence
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 129 of 1057
Home Heating Systems in US
Household Heating Systems: Although several different types of fuels are available
to heat our homes, nearly half of use natural gas. | Source: Buildings Energy Data
Book 2011 3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 130 of 1057
Delivery Method
•Radiation –heated by radiant energy. Radiant
floor heating can use 40% of the energy of
convective heating systems.
•Baseboard or fluid registers on the outer
portions of the home cause natural convection.
•Furnaces and fans in heaters create forced
convection.
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 131 of 1057
Zoning
•Increasing number of controlled zones decreases
amount of heat needed. When two or more areas
can be kept at different temperatures based on need
or occupancy, savings may occur.
•Home furnaces controlled by single thermostat
cannot benefit from zoning. Attempts to zone a
forced air system often reduce heating efficiency
and have a greater impact on air source heat
pumps.
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 132 of 1057
Zoning
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 133 of 1057
Fuel Used to Heat the Transfer Fluid
•Radiant surfaces can be fueled by any source.
–Electric use electric resistance coils.
–Transfer liquids can be heated by electricity, natural
gas or any other fuel.
•Forced and natural convection systems can be
fueled by natural gas, electric elements, heat pump,
wood, or any other fuel.
•Low carbon future could use dual fuel sources.
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 134 of 1057
Fuel Delivery Efficiency
•Natural gas limited to 98% efficiency when exhausting
combustion product outside. Natural gas heat pumps
with a coefficient of performance (COP) around 1.5
under development.
•Electricity has a low threshold of 100% efficient with
resistive electric, although an air source heat pump
backed by resistance can operate below 100% during
defrost and low temperatures. Electric heat pumps can
approach an annual COP of 4, depending on outside
temperature, soil type and heat pump type.
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 135 of 1057
Fuel Delivery Efficiency– cont.
•Ground source heat pump
–Highest performing units
–Utilize stored energy of the sun in the earth to transfer heat
•Highest performing air source heat pumps are
ductless units
–Perfectly coupled between interior and exterior units.
–CO2 heat pumps being tested in the US do not have the
exterior temperature issues that other air source heat
pumps have with efficiency degradation due to cold
weather (NW CO2 Pilots)
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 136 of 1057
Fuel Delivery Efficiency – cont.
•Lowest efficiency fuel is wood
–An average of 50% of the heat makes it into the
space.
–If the damper is left open on a chimney flue, the
house will evacuate the heat inside after the fire goes
out through the stack affect.
–One of the best home audit measures is to plug the
flue of unused fireplaces to reduce lost heat.
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 137 of 1057
First Cost of Technologies
•Ground source heat pumps add $10,000 to
$20,000 to a home budget if feasible.
•In-floor radiant systems add $10,000 to $15,000
to normal forced air system in new construction.
•Full home multi-head zoned ductless units can
be $10,000 to $30,000 above baseline natural
gas systems.
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 138 of 1057
First Costs
12
Ground Source Heat Pump
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 139 of 1057
Home Heating Needed
•Size:smaller is better
•Insulation:more is better
•Location and installation of ductwork:inside is better
•Infiltration: none is better, need Energy Recovery
Ventilator
•Number of people: more is better
•Humidity:some is better than none
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 140 of 1057
Home Heat Loss
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 141 of 1057
Climate Zones
15
https://basc.pnnl.gov/images/iecc-climate-zone-map
RTF identifies
zones 4, 5 & 6
zones 1, 2 & 3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 142 of 1057
Home Heat Loss Calculation
•Most loss from conduction through envelope and
infiltration/exfiltration through cracks.
•EL = UA(Tin-Tout)
–U is thermal conductivity,
–A is the surface area of the home, and
–Tin is temperature inside and Tout temperature outside
•1,000 ft2 home with 8 foot ceilings has an area of 3,760
ft2. If the average R value is 25, it has a U factor of .04
BTU/hr*ft2*F.
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 143 of 1057
•If average outdoor temperature during the heating
season is 42°and the set point is 72°, then the hourly
heat loss is 4,512 BTU/hour
–.04*3,760*30 = 4,512 BTUs or 3,248,640 BTU’s per month. That
is 951 kWh with electric resistance heat, about 560 kWh with an
air source heat pump, and about 33 therms.
•At Avista’s current rates, losses would be $95 for
resistance heat, $56 for a heat pump, and $30 for natural
gas.
•This is for a very small home with very good insulation in
Northwest climate zone 4 ignoring heat gain from
humans or solar.
17
Cost of Heat Loss –Example
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 144 of 1057
Heating Degree Days (HDD)
•Difference between 65°and outside temperature
measured in days.
•6,800 HDD: Spokane average of a 38°difference
between 65°and outside over 6 month heating season.
•4,700 HDD: Seattle average of a 29°difference between
65°and outside over 6 month heating season.
•Heat pumps operate in their wheelhouse in Seattle and
below optimum in Spokane.
18
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 145 of 1057
Fuel Cost
•Natural Gas heat is 1/3 the cost per BTU compared
to electricity.
–The average electric home costs more to operate than a
natural gas home in climate zones 2 and 3 at Avista’s
current gas and electric prices.
•Avista’s electric peak often occurs at the coldest
point in December, so electric homes highest
consumption coincides with our highest load.
–This includes net zero homes which don’t produce during
our winter peak.
19
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 146 of 1057
Questions
20
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 147 of 1057
Resource Adequacy and Effective Load
Carrying Capability
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 148 of 1057
Why Does Resource Adequacy Matter?
Helps determine how much new capacity our customers
need.
Informs “us” how much capacity we rely on from our
neighbors.
Provides insight on how certain resource help provide
reliable capacity.
2
We discovered this type of analysis requires a lot of process time,
specific locational assumptions for renewable resources, and is an
“art” rather than a specific science.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 149 of 1057
Loss of Load Probability (LOLP)
LOLP is the current regional measurement for resource adequacy.
Measures probability of a resource adequacy deficiency over a one
year time period.
No regulatory body enforces a particular resource adequacy
standard or metric.
This is a great measure of probability of reliability, but…according to
the NPCC…
−“No measure of magnitude
−No measure of duration
−No measure of frequency within the year
−Two scenarios with same LOLP can have vastly different curtailment magnitude
and duration”
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 150 of 1057
Reliability Metrics Options
What we are modeling for?
Events not serving all load and reserve requirements due to
insufficient resources/market availability
Metrics
LOLP: Loss of Load Probability
−Number of draws with an event (probability of a draw with an event)
LOLH: Loss of Load Hours
−Hours with events / iterations (time in hours)
LOLE: Loss of Load Events
−Days with events / iterations (time in days)
EUE: Expected Unserved Energy
−Average MWh not served during an event (Magnitude)
ELCC: Effective Load Carrying Capability
−Percentage of resource capacity equal to CTs4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 151 of 1057
Model Assumptions & Challenges
The Model
Built in Excel with What’s Best optimizer
1,000 simulations
Randomizes:
−Forced outages
−80 years of hydro data
−128 years of weather data (load &
generation)
Challenges:
−Time: three days to run per study, to
date over 70 studies since April have
been completed.
−Randomization: may not get same
results with same assumptions.
−This is becoming more of an “art” then
a “science”
The Key Assumptions
2030 load and resources
Average peak load: 1,778 MW (Winter),
1,636 MW (Summer)
Average hourly load: 1,081 MW
Major resource changes from today: No
Lancaster, less Mid-C, no WNP-3 contract
Off-peak market purchases limited to 1,000
MW
On-peak market purchase limited to 400
MW
When daily temps > 84 and < 4 degrees
Fahrenheit, market purchases are limited
250 MW
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 152 of 1057
Without resource additions, what is our
reliability metrics in 2030?
LOLP: 27.9%
LOLH: 18.29
LOLE: 1.41
EUE: 3,430 MWh
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 153 of 1057
How much capacity is required to be at
5% LOLP?
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
14.0%
1 2 3 4 5 6 7 8 9 10 11 12
Lo
s
s

o
f

L
o
a
d

P
r
o
b
a
b
i
l
i
t
y
Month
LOLP: 4.9%
LOLH: 1.85
LOLE: 0.16
EUE: 318.7 MWh
Add 245 MW (winter) / 182 MW
(summer) two unit CT
245 MW new gen / 1,778 MW
average peak load = 13.8%
planning margin
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 154 of 1057
LOLP at Different Levels of Capacity
Additions
y = 2E-05x2 -0.0079x + 1.0335R² = 0.9821
0%
1%
2%
3%
4%
5%
6%
7%
215 220 225 230 235 240 245 250
LO
L
P
Capacity Additions (Winter-MW)
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 155 of 1057
Does Wind Improve Reliability?
Wind can improve reliability, but not equal to a CT
Location diversification improves capacity credit!
Studies to date include two studies:
−Case 1: NW Wind
−Case 2: Montana Wind
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 156 of 1057
Case 1: NW Wind
1st study: exclude Palouse Wind
2nd study: decrease CTs by 25 MW and add more wind until 5%
LOLP is achieved
Concerns:
How will other NW projects with less correlation to Palouse change this
result?
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Palouse Wind excluded 5.5%1.86 0.17 307
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
+ 300 MW wind 5.5%1.80 0.15 296
+ 400 MW wind 5.5%1.72 0.14 256
+ 500 MW wind 5.4%1.70 0.14 280
Reference case -15 MW CT 5.5%1.93 0.17 319
1)5% LOLP never achieved
2)other metrics improve with more wind
3)Suggest ELCC for NW wind:
15/300= 5%
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 157 of 1057
Case 2: Montana Wind
Reduce CTs by 25 MW, add wind until 5% LOLP is maintained
Concerns:
Low temperature cut outs, wind turbines must curtail when temperatures are
below -30 Celsius (-22 F)
All Montana wind regimes may not be the same
Earlier analysis showed 30% capacity contribution with alternate data
Avista needs to perform more studies including larger reduction in capacity deficit
positions
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
+ 60 MW MT wind 4.9%1.49 0.13 249
+ 70 MW MT wind 4.9%1.39 0.12 203
+ 100 MW MT wind 4.1%1.18 0.10 205
ELCC for MT Wind: 25/60= 42%
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 158 of 1057
Does Solar Improve Reliability?
Solar studies are performed similar to wind, but use an
earlier version of the model
CT reductions:
−76 MW Winter
−56 MW Summer
Never get to 5% LOLP!
Summer LOLP reduces to zero in high cases
Conducted a new reference case with 20 MW less CT
winter capacity to arrive at a 5.8% LOLP
ELCC is 2.2% (20 / 900)
Case LOLP LOLH LOLE EUE
Reference 5.0%1.75 0.15 254
Reference –76 MW CTs 9.4%3.73 0.30 689
300 MW 7.8%2.71 0.22 440
600 MW 7.6%2.29 0.21 353
900 MW 5.8%2.14 0.18 350
Reference –20 MW CT 5.8%1.75 0.17 327
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 159 of 1057
Does Demand Response (DR) Improve
Reliability?
Demand response temporarily reduces load for a period of time
Studied three scenarios compared to “CT” reference case
25 MW, 4 hour reduction up to 10 times per year
25 MW, 8 hour reduction up to 10 times per year
25 MW, 16 hour reduction up to 10 times per year
Proposed ELCC:
4 hour: 8% (2 MW / 25 MW)
8 hour: 60% (15 MW / 25 MW)
16 hour: 64% (16 MW / 25 MW)
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
4 hour duration 6.1%1.99 0.18 338
8 hour duration 5.7%1.87 0.16 316
16 hour duration 5.6%1.67 0.15 282
Reference case -15 MW CT 5.5%1.93 0.17 319
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 160 of 1057
Does Storage Improve Reliability?
Storage moves energy, but doesn’t create energy!
Storage can lose 10% to 50% of the energy it stores
Study assumes 90% round trip efficiency (i.e. Lithium-
ion technology)
Storage requires the ability to add additional energy
to the system from another source to add significant
capacity value
Higher storage penetration may lead to less capacity
contribution
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 161 of 1057
Storage Results
Case LOLP LOLH LOLE EUE
Reference case 4.9%1.85 0.16 319
Reference case -25 MW CT 6.4%2.16 0.20 359
25 MW, 4 hour storage 5.8%2.13 0.19 352
25 MW, 16 hour storage 5.7%2.04 0.17 315
25 MW, 40 hour storage 5.6%1.92 0.17 387
25 MW, 4 hour storage,w/ 50 MW solar 5.6%1.96 0.18 330
50 MW, 4 hour storage,w/ 50 MW Solar 5.3%1.95 0.17 302
50 MW, 4 hour storage,w/ 100 MW Solar 5.2%2.23 0.19 379
Avista proposes to use the following capacity credits for low capacity additions
4 hour: 56% (14 MW / 25 MW)
16 hour: 52% (13 MW / 25 MW)
40 hour: 48% (12 MW / 25 MW)
A third party analysis estimates 10% capacity credit results without new energy
resources. With new energy resources its between 12% and 60%
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 162 of 1057
Resource Combination Analysis
What if we remove new “CTs” and planned our system
with non-traditional resources
Case LOLP LOLH LOLE EUE
No new resources 27.9%18.3 1.41 3,430
Reference case (add 245 MW CT)4.9%1.85 0.16 319
Add: 200 MW MT wind, 155 MW NW wind, 50 MW
DR, 125 MW 6 hour storage, and 250 MW solar
6.3%2.43 0.20 429
Add: 200 MW MT wind, 245 MW NW wind, 50 MW
DR, 150 MW 6 hour storage, and 350 MW solar
4.8%2.40 0.17 487
Exclude Colstrip from portfolio & no new resources 75.8%106.8 8.43 21,265
Add: 400 MW MT wind, 400 MW NW wind, 100 MW
DR,200 MW 6 hour storage, and 500 MW solar
13.2%5.46 0.45 1,174
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 163 of 1057
Third Party ELCC Analysis
Slides not included at this time for distribution or webcast
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 164 of 1057
2019 Electric IRP Key Assumptions
James Gall, IRP Manager
John Lyons, Senior Resource Policy Analyst
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 165 of 1057
Existing Forms of Carbon Regulation
•Indirect: Renewable resource additions, higher RPS
•Carbon tax: British Columbia
•Direct regulation: Affordable Clean Energy Rule
•Cap and trade: AB 32 in California
•State mandates: Oregon SB 1547 and emissions
performance standards
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 166 of 1057
Renewables
•Renewables drive emissions lower, but may be indirect to the
location of the renewable generation’s location
•RPS standards in each state (large utility goals shown below)
–WA: 15% by 2020 (100% clean proposals)
–OR: 50% goal by 2040
–CA: 45% by 2023, 50% by 2026, 60% goal by end of 2030, and 100% by 2045 (SB 100)
–NV: 25% by 2025 (50% by 2030, needs another yes vote in 2020)
–AZ: 15% by 2025 (50% by 2035 failed in Nov. election)
–NM: 20% by 2020
–CO: 30% by 2020 (Higher proposals expected)
–MT: 15%
•Consumer Driven Renewables
–Rooftop solar
–Large commercial direct investment
–Green tariffs (jurisdictional and organizational)
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 167 of 1057
Direct Regulation
Washington SB 6001-Emissions performance standard limits “baseload”
generation to 930 lbs of CO2 per MWh for new resources or contracts five
years or longer
Affordable Clean Energy Rule (ACE) –August 2018 replacement proposal
for the Clean Power Plan
1.Defines the “best system of emission reduction” (BSER) for existing plants as
on-site, heat-rate efficiency improvements;
2.Provides “candidate technologies” for states to establish standards of
performance for their plans;
3.Updates the New Source Review (NSR) permitting program to encourage
efficiency improvements at existing plants; and
4.Aligns regulations under CAA section 111(d) to give states time and flexibility to
develop their own plans.
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 168 of 1057
Carbon Regulation and Taxes
•AB 32 in California
–1990 levels by 2020 and 80% below 1990 levels by 2050
–Typically modeled as a “price” adder due to economy-wide trading
system, using minimum price
•Oregon
–Coal to Clean: coal can no longer serve Oregon loads after 2030/2035
–Cap and trade program expectations in next legislative session
•Washington 100% Clean Proposals
•Affordable Clean Energy Rule
•Canadian Carbon Taxes
–British Columbia: $30/metric ton (Can$)
–Alberta: $30/metric ton (Can$)
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 169 of 1057
Aurora Inputs
•Regional loads
•Fuel prices
•Hydro levels
•Wind variation
•Environmental constraints
•Resource availability
•Transmission
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 170 of 1057
Regional Loads
•Forecast load growth for all Western Interconnect regions
•Consider both peak and energy growth
•Use latest load forecast from Epis
•Stochastic modeling simulates load changes due to weather
and considers regional correlation of weather patterns
•Economically driven load changes are difficult to quantify and
are usually picked up as IRPs are published
•Peak load is increasingly more difficult to quantify as “Demand
Response” programs may cause data integrity issues
•Energy demand forecasts need to be net of conservation,
electric vehicle forecasts, and behind the meter generation
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 171 of 1057
California/Baja
Northwest
Desert SW
Rocky Mtns
Canada
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
220,000
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Peak Forecast
Energy & Peak Forecast
Energy AAGR Change
Canada 1.32%
Rocky Mtns.0.53%
Desert SW 1.84%
California 0.40%
Northwest 0.42%
Total 0.83%
Peak AAGR Change
Canada 1.44%
Rocky Mtns.0.52%
Desert SW 1.89%
California -0.06%
Northwest 0.44%
Total 0.72%8
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
220,000
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Energy Forecast
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 172 of 1057
Electric Vehicles (EV)
•Current load shapes have low EV penetration, but by 2030, load
shapes will differ due to EV and behind the meter solar
•EV percentage of new vehicle sales forecast by 2030
•After 2030, EV growth equals traditional vehicle growth (half of
population growth)
9 http://evadoption.com/ev-market-share/ev-market-share-state/
0%
5%
10%
15%
20%
25%
30%
AZ CA CO ID MT NM NV OR UT WA WY
Pe
r
c
e
n
t
a
g
e

o
f

N
e
w

V
e
h
i
c
l
e

S
a
l
e
s
EV Sales Forecast
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 173 of 1057
EV Load Shaping
A combined hourly load shape for EV’s will be combined
using Avista EV load data from its Pilot Project
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
kW
Hour of the Day
EV Daily Load Shapes
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 174 of 1057
Rooftop Solar
•Rooftop solar impacts future load growth and changes its
hourly profile
•Future rooftop solar growth depends on policy choices
•Assumes 20-30% growth, before leveling off to 3% long
run growth in 2020s
11
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Western Interconnect Consumer Solar
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 175 of 1057
Natural Gas Prices
•Natural gas prices among the most difficult inputs to quantify
•A combination of forward prices and consultant studies will be
used for this IRP. This work should be complete by December
2018 (i.e. deterministic forecast)
•500 different prices using an auto regressive technique will be
modeled, the mean value of the 500 simulations will be equal
to the deterministic forecast
•A controversial input for these prices is the amount of
variance within the 500 simulations
•Historically prices were highly volatile, recent history is more
stable
•Final variance estimates consider current market volatility and
implied variance from options contracts
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 176 of 1057
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
$
p
e
r

D
t
h
Consultant 1 Consultant 2 2013 IRP2015 IRP 2017 IRP 2019 IRPActualsForwards (10/22/2018)
Henry Hub Natural Gas Prices *
* Based on methodology described above, to be updated
Levelized price is $4.57/dth (2020-39)
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 177 of 1057
Coal Prices
•Decreased demand for US based coal with lower natural
gas prices and state and federal regulations, but
potential exports may stabilize the industry
•Western US coal plants typically have long-term
contracts and many are mine mouth
•Rail coal projects incur diesel price risk
•Prices will be based on review of coal plant publically
available prices and EIA mine mouth and rail forecasts,
currently the price escalator is ~2.5%
•Colstrip Fuel Prices will be discussed at the February
TAC meeting with final fuel forecasts
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 178 of 1057
Hydro
•80 years of hydro conditions are used for the Northwest
states, British Columbia and California provided by BPA
–Hydro levels change monthly
–Aurora dispatches the monthly hydro based on whether its run-
of-river or storage
•For stochastic studies the hydro levels will be randomly
drawn from the 80-year record
•Columbia River Treaty could change regional hydro
patterns, but until there is a new treaty, no changes will
be included
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 179 of 1057
Northwest State Hydro Volatility
Mean: 15,587 aMW
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 180 of 1057
Wind
•Modeling technique
−Autoregressive technique to simulate output in similar to reported data
available from BPA, CAISO, and other publically available data sources-
also considers correlation between regions
−For stochastic studies several wind curves, will be drawn from to
simulate variation in wind output each year for each of the 500 draws
•Oversupply modeling technique
−RECs and PTC’s have caused wind facilities to economically generate
in oversupply periods in the Northwest-particularly in the spring months
−Wind is modeled in Aurora as a negative marginal cost, allowing for the
model to simulate negative prices
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 181 of 1057
NW Wind Capacity Factor History
Source: https://transmission.bpa.gov/business/operations/wind/18
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Annual Capacity Factor
Pr
o
b
a
b
i
l
i
t
y
Portion of Hours Less Than 5% Capacity Factor
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Monthly Capacity Factor
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 182 of 1057
Western Interconnect Coal Retirements
The price forecast simulation may find additional coal retirements in the later half of
the study period
19
Plant Units State
Summer
Capacity
(MW)
Retirement
Year Proposed
Fuel
Conversion
Apache Station 2 Arizona 175 2017 Committed Natural gas
Hardin 1 Montana 107 2018 Proposed
Naughton 3 Wyoming 330 2018 Proposed
Navajo 1 to 3 Arizona 2,250 2019 Committed
Centralia Complex 1 Washington 670 2020 Committed
Centralia Complex 2 Washington 670 2025 Committed
Cholla 4 Arizona 380 2020 Proposed Natural gas
Boardman (OR)1 Oregon 585 2021 Committed
North Valmy 1 Nevada 254 2021 Proposed
Colstrip 1 & 2 Montana 614 2022 Committed
Comanche 1 Colorado 325 2022 Proposed
Nucla 1-3, ST4 Colorado 100 2022 Proposed
San Juan Generating Station 1 & 4 New Mexico 847 2022 Proposed
TS Power Plant ST Nevada 218 2022 Proposed
Cholla 1 & 3 Arizona 387 2025 Proposed
Comanche 2 Colorado 335 2025 Proposed
Craig (CO)1 Colorado 428 2025 Committed
Intermountain ST1 & ST2 Utah 1,800 2025 Proposed Natural gas
North Valmy 2 Nevada 268 2025 Proposed
Dave Johnston 1 to 4 Wyoming 762 2027 Proposed
Jim Bridger 1 Wyoming 531 2028 Proposed
Naughton 1 & 2 Wyoming 357 2029 Proposed
Hayden 1 & 2 Colorado 446 2030 Proposed
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 183 of 1057
Initiative 1631
•2018 Carbon Emissions Fee Measure
–$15 per metric ton of carbon emissions fee on January 1,
2020
–Increase fee $2 per year until state emissions goals met
–Direct proceeds to various programs and projects to
improve carbon emissions
•Failed with 56.55% voting against the measure
–Avista counties 67% voting against
•Will update TAC and modeling for new legislation in the
upcoming Washington session
20
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 184 of 1057
City of Spokane 100% Renewable Goal
•Spokane City Council adopts aspirational goal to have
the city served with all renewable power by 2030 (August
2018)
•Committee will be formed to scope and define this
ordinance
–Net renewable or something else?
–How it will be ramped in?
–Implications and help for low income and other at risk
groups?
–Rate issues
21
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 185 of 1057
2019 IRP Futures and Scenarios
James Gall, IRP Manager
John Lyons, Senior Resource Policy Analyst
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 186 of 1057
IRP Modeling Plan for Environmental
Policies
•No expected case due to potential policy uncertainty
•Three futures used rather than an expected case +
scenarios
•Alternative futures and scenarios can also be studied,
but will need to be minimal due to resource constraints
•Proposed Futures (500 simulations each)
1.Existing policies & trends
2.Social Cost of Carbon
3.Clean Resources
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 187 of 1057
Existing Policies & Trends
Major future assumption change is a greenhouse gas price distribution with:
•1/3 probability of no pricing
•1/3 probability of $10/metric ton (2018$) escalating at 2.5% year
−Begins in 2025
−Applies to all of Western Interconnect resources
•1/3 probability of cap and trade of 20% below 1990 levels
−20% goal by 2030
−40% goal by 2040
−Applies to all of Western Interconnect
−An implied CO2 price will be a result of each study
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 188 of 1057
Social Cost of Carbon (SCC)
•No CO2 cost penalties for dispatch, the SCC will be included
as a cost in resource and energy efficiency acquisitions
•Pricing will be a distribution of costs from the Interagency
Working Group on Social Cost of Carbon (Aug 2016)
−1/3 probability of 5.0% discount rate pricing distribution (90th
Confidence Level)
−1/3 probability of 3.0% discount rate pricing distribution (90th
Confidence Level)
−1/3 probability of 2.5% discount rate pricing distribution (90th
Confidence Level)
•SCC will be applied to the Washington portion of load service
for Avista resource portfolios
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 189 of 1057
Social Cost of Carbon Pricing
Distribution From
5
Use 90th confidence interval for each of the
three distributions for the 500 simulations Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 190 of 1057
Social Cost of Carbon
Confidence Interval
90th Confidence Interval Ranges
Distribution of 500 Simulations
Pr
o
b
a
b
i
l
i
t
y

o
f

O
c
c
u
r
a
n
c
e
$ per Metric Ton (2007$)
Mean Price is ~$25/metric ton
Prices will be pulled evenly
from the three discount rate
scenarios
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 191 of 1057
Clean Resource Future
•Washington: 100% of load met by “clean” resources on a “net” basis
−80% by 2030, 90% by 2040, and 100% by 2050
−Qualifying resources can be sourced from anywhere in the Western
Interconnect
−Up to 20% of resources can be “RECs” from outside of the region or
alternative compliance
−Price cap of $5 per metric ton ($2018) beginning in 2030 and 1%
revenue requirement for portfolio modeling
•Oregon cap and trade
−20% below 1990 levels by 2030
−50% below 1990 levels by 2040
−80% below 1990 levels by 2050
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 192 of 1057
Additional Scenarios
Aurora Studies
•High natural gas prices (deterministic)
•Low natural gas prices (deterministic)
•Social Cost of Carbon (stochastic)
•High Colstrip fuel cost (deterministic)
•Colstrip shutdown (stochastic)
PRiSM Studies
•Study from each of the Aurora cases
•Colstrip closes in 2027
•Colstrip closes in 2035
•High cost to retain Colstrip (with low gas)
•Low and high load growth, alternative load cases (i.e. electrification, EV, behind the meter generation, power-to-gas, etc.)
•Lancaster continues
•High cost to retain Colstrip
•Colstrip fuel prices
•Conservation TRC vs. UCT
•Tipping point scenarios
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 193 of 1057
High and Low Natural Gas Prices
•Deterministic studies to show the impacts of
consistently lower or higher natural gas prices
than the expected price forecast
•Low case will have existing price levels and not
increase
•High case level TBD –more details forthcoming
at February 2019 TAC meeting
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 194 of 1057
Social Cost of Carbon
•Differs from the future discussed earlier by
including the price for dispatch for all plants in
the Western Interconnect
•Will include the same prices as discussed in the
SCC future
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 195 of 1057
Colstrip Basic Assumptions
•Avista’s share of fuel, O&M, and capital investment costs
•Increased common costs due to shut down of units 1 & 2 in 2022
•Selective catalytic reduction (SCR) –2027 and 2028, includes
capital costs, ammonia and fixed and variable O&M to reduce NOx
•Enhanced mercury controls
•Coal Combustion Residuals (CCR’s)
–Coal dry ash handling (2022) and long term storage
•Smart Burn combustion controls installed in 2017
•Water management
•Depreciation schedule shortened to 2027 per merger agreement
•Additional details on the specifics will be provided in TAC 4
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 196 of 1057
Colstrip Scenarios
•Retire Colstrip Units #3 and #4 in 2027 as an
alternative to SCR investment
•Retire Colstrip Units #3 and #4 in 2035 as an
alternative to SCR investment
•Colstrip fuel prices increase 30%
•High cost to retain Colstrip case (next slide)
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 197 of 1057
High Cost to Retain Colstrip Case
•This case answers questions about several higher cost issues
impacting Colstrip’s compliance cost
•This scenario uses assumptions in the three futures, except:
–EPA expands regional air quality programs and rules to the western
U.S. such as CASPR and NAAQS requiring SCR installation on Units
#3 and #4 at an earlier date (End of 2023)
–Units #1 and #2 shut down earlier than announced, increasing the
amount of shared costs cover by Units #3 and #4 (End of 2019)
–MACT PM/MATS RTR compliance problems. Dry system required to
remove particulates and reduce water use (End of 2023)
–No enhancement to existing SO2 scrubbers as no current regulation
drives reduction levels beyond current plant emissions
–Higher Colstrip fuel costs
–Low natural gas cost environment
–Specific cost details will be provided in TAC 4
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 198 of 1057
Load Growth Scenarios
•High and low load growth scenarios due to
economic changes in the service territory
•Potential load study scenarios
–High EV penetration case (120,000 EVs by 2045)
–Behind-the-meter generation (10% penetration by 2030)
–Fuel switching electric to natural gas
–Fuel switching natural gas to electric
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 199 of 1057
Lancaster Continues
•Lancaster PPA currently ends October 2026
•PPA has an option to extend the contract 5 years
at a negotiated price
•Implications of extending the PPA or purchasing
the plant beyond the current end of the PPA
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 200 of 1057
Alternative Energy Efficiency Evaluations
•All cases will model cost effectiveness of energy
efficiency using the total resource cost (TRC) in
Washington and the utility cost test (UCT) in
Idaho
•This scenario tests both methods of evaluation
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 201 of 1057
Tipping Point Analyses
•Estimates the cost reduction or operating
characteristics needed to change the resource
strategy
–Are there any assumptions that need to be tested to
find the cost tipping point?
–Past studies have included capital costs for solar and
storage
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 202 of 1057
Attendees: TAC 2, Tuesday, November 27, 2018 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Jennifer Snyder, Washington UTC; Amy Wheeless, NW Energy Coalition; Steve Johnson, Washington UTC; Michael Eldred, Idaho Public Utilities Commission; Matt Nykiel, Idaho Conservation League; Shelby Herber, Idaho Conservation League; Dave Van Hersett, Avista residential customer; John Barber, Rockwood Retirement Community; Brian Parker, 350.org; Jørgen Rasmussen, Solar
Acres Farm; Kirsten Wilson, DES Energy Program; Garrett Brown Avista; Clint Kalich, Avista; Barry Kathrens, 350.org; Pauline Druffel, 350 Spokane; Thomas Dempsey, Avista; Terrence Browne, Avista; Darrell Soyars, Avista; Scott Kinney, Avista; Mary Tyrie, Avista; Tom Lienhard, Avista; Tom Pardee, Avista; Kaylene Schultz, Avista; Amber Gifford, Avista; Rachelle Farnsworth, Idaho Public Utilities Commission; James
Gall, Avista; and Gerry Snow, PERA.
Phone Participants:
Doug Howell, Sierra Club; Sarah Laycock, Washington State Attorney General’s Office;
Mike Starrett, Power Council; Nancy Estep, NW Energy Coalition.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses are in italics, and
significant points raised by presenters that are not shown on the slides are also
included.

TAC Expectations and Process Overview, John Lyons
Matt Nykiel: On the topics, what is available and when, and what will not be available?
Avista is developing a matrix of the data to indicate timing and availability of data.
Doug Howell: Why are there less meetings (5 instead of 6) for this IRP? We are having
fuller agendas in five meetings rather than spreading out to six.

2019 IRP Modeling Process Overview, James Gall
Matt Nykiel: Which of these are going to be available publically? For the February TAC
meeting – market price results high level inputs, annual fuel, demand and resources
today. Existing publically available data, transmission, and the load forecast provided in
the last TAC meeting. Resource position will be next TAC meeting, Demand Side
Management and Demand Response information will be at a later meeting. High level
or detail level would be available in FERC level data.
(See separate data matrix file sent with these meeting notes)
Steve Johnson: Simple list of items, where they are found and when they will be
released.
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Doug Howell: PSE has distinct scenarios for load, gas and fuel prices. How is Avista
different in the process? We will hit this later today.
Brian Parker: Will proprietary data be included in the list? Why is it proprietary? Often
contractual and market intelligence data is proprietary, such as the natural gas price
forecast we purchase.
Doug Howell: Across the country we now have non-disclosure agreements in eight
different states. Hoping to have them soon in Louisiana with the same owners as PSE
(Puget Sound Energy). So we can have a consultant run the model, we want the data
under a nondisclosure agreement. We hope to have one with PSE too.
Doug Howell: Are known and expected resource retirements included? Includes
publically announced retirements. If plants are uneconomic when modeled, but not
announced, Aurora would shut those plants down too.
James Gall: For the OWI (Oregon, Washington and Idaho) region, which Avista has
modeled as one bubble in Aurora, we will try to split this region up by state to
accommodate state-level resource policy decisions.
Amy Wheeless: What about resource shuffling? This will be covered later.
Matt Nykiel: Do we have a guideline for what will be modeled stochastically versus
deterministically? Avista tries to run as many studies as we can stochastically, but each
study takes about a week to complete. We generally default to deterministic studies as
we run out of modeling time which is limited.
PRiSM Section
Doug Howell: What is the rationale for splitting up the region? [OWI being modeled as
separate areas instead of one area] Splitting up the region allows us to account for a
situation where a state or city wants a unique policy that differs from the rest of the
region, such as a 100% renewable energy requirement for a city.
Mike Starrett: How are we going to do this for prudence? What if the city and state are
not aligned like PGE and the City of Spokane. Would probably develop a green tariff.
Clint Kalich: This is an exercise for information. What costs might be if this type of policy
occurred. The IRP doesn’t promote tariffs, but informs the development of them.
Steve Johnson: Boutique resource portfolios for new resources from PSE. Shows cost
differentials for core and unique customers.
Matt Nykiel: How practically can we identify them?
James Gall: More of an accounting mechanism. We know generation, but need to
account for overages and surplus.
Brian Parker: What will we be able to share from the study?
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Schedule 1a, Page 204 of 1057
James Gall: We would be able to share what is selected by PRiSM and the least cost
results. We will talk about Spokane later.
Doug Howell: I have heartburn about long-term impacts, like coal ash having horribly
wrong cost estimates, and how to reconcile them. Also low balling cost estimates of
wind and solar. And climate cost estimates resulting in obsolete resources in the future.
Slide 10 – 11
James Gall: We are taking market risk. Others in scenario risk.
Amy Wheeless: Risks? Market load, hydro and wind variability, not other risks.
Clint Kalich: Qualitative choices.
John Lyons: Scenarios are used for fundamentally different futures with second order
change, like a future with a new low-cost efficient car battery that changes the market
for electric cars.
Amy Wheeless: BPA used an efficient frontier with how they picked DSM.
James Gall: We look at all 5,000 plus DSM measures, so conservation lowers risk, cost,
and reduces summer/winter peak.

Generation Resource Options, James Gall
Steve Johnson: So actual runs will have the transmission cost where applicable later
on.
Matt Nykiel: When will gas prices be locked in? Probably after the February meeting.
Steve Johnson: Price excursions with the British Columbia pipeline. Will discuss later
since Tom Pardee (Natural Gas IRP Manager) is not in the room.
John Barber: What is the hybrid technology? LMS 100 is a mix of frame and aero
derivative. The compressor section compresses, cools and reinjects the air. It is more
efficient than a peaker, but not as efficient as a combined-cycle plant.
Steve Johnson: Does Avista model oil backup? No, we have been able to rely on the
pipelines not being fully subscribed. Now that they are fully subscribed, we will need to
decide if we need to model oil, LNG or purchase gas as a backup.
Jennifer Snyder: Ask PSE (Puget Sound Energy) if they got any traction in offshore
wind.
Steve Johnson: Where does Avista get its updated data for expected capacity factors?
How does Avista compare unknowns? Wind vs. solar. Avista has gotten data from
renewable RFPs with wind at a 38% capacity factor, but our actual experience has been
much lower. We only pay by the megawatt-hour for actual generation under a contract.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 205 of 1057
Wind on Avista’s system is in the high 30s and high 40s for wind projects in Montana.
Solar capacity factors are also for RFPs, as well as generation from the solar projects at
Lind and Boulder Park. There is also solar data from NOAA, which is being used by
bidders.
John Barber: Just lithium ion? Yes, in conjunction with solar and all types of battery
storage for other projects.
Steve Johnson: Ramping costs, shut off, curtailment. Yes, we can shut it off wind, but
still have to pay for it.
James Gall: Modeling on an hourly basis. Some may have PPAs with certain hours or
ramping.
Amy Wheeless: Biomass seems pretty big. Yes, we have the opportunity to do one
biomass project that big. Is nuclear included? Yes, small nuclear is being modeled.
John Barber: Doesn’t biomass operate as a baseload plant and not as a peaker. Usually
true, this project would operate more as a peaking biomass facility in the winter.
Pauline Druffel: Doesn’t biomass produce greenhouse gases? Yes, but biomass is
carbon neutral under Washington law.
Page 5 – Other Clean Resource Options
Amy Wheeless: Are hydro PPA’s going to be included? Yes, on a later slide (Slide #13)
Slide #6 - Storage Technologies
Thomas Dempsey: Liquid air is a long-term energy storage using solar and wind
generation to compress and liquefy the air. When using this system, the plant does not
have to compress air, so we would get full use of the generating resource.
Steve Johnson: What are the efficiencies? 60 – 70% round trip efficiency. Hydrolysis is
only 25% efficient.
James Gall: We are using the Lazard Study, and a new version should be available next
month, so we will use the most up-to-date costs available.
Steve Johnson: For hydro and Post Falls. PSE costs for rebuilding Snoqualmie Falls
were much higher than expected. Make sure you are modeling these hydro rebuilding
costs really carefully. The project economics didn’t work out.
Steve Johnson: Power purchase options. Design a model to capture the value of an
asset’s value of these contracts. Green value. Very important to know it would serve
load with the value of different kinds of resources. And articulate why, how, and ways
resources are driving costs meeting loads with market options.
Resource Option Spreadsheet
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 206 of 1057
Amy Wheeless: What is the deadline for comments on the resource spreadsheet? By
the middle to end of January.
Steve Johnson: With the 20-year timeframe, are we adding more noise than necessary?
Would retrofitting be cheaper? Avista models retrofitting options if we know about the
potentials.

Home Heating Technologies Overview, Tom Lienhard Garrett Brown: What is the payback on slide 11 [First cost of technologies]? In floor
radiant heat uses less than half the energy. Good if staying in the house for 20 years.
Need to work to overcome the first costs. When they do a good job.
Barry Kathrens: Comfort is another benefit. My woodshop has radiant floor heat and
adds like an extra dollar a day.
Tom Lienhard: Maybe we need an Air B&B for people to be able to try out a good
efficient house in the winter.
Kirsten Wilson: We were able to remove and replace the old heating system for an
additional $15,000 in an existing structure. But we are both engineers.
Jørgen Rasmussen: How does a CO2 heat pump compare. COP of 3, equal or better
than 96%, and is about $5,000 for the unit.
Brian Parker: I came here from California where they were more sophisticated about
these matters. I’ve had trouble finding HVAC contractors who could do certain efficiency
calculations. Either they wouldn’t show up or they didn’t come back. Yes, it is a design
issue and requires meeting with the right HVAC installers to make these things happen.
Tom Lienhard: 10% humidity when cold in continental climate works the same way. 72
degrees feels like 64 degrees since heat can’t transfer. At 45% relative humidity, 72
degrees feels like 72 degrees. This also affects heat pumps here where there is general
not as much humidity.
Tom Lienhard: The RTF uses zones 1, 2 and 3. Avista is in zones 2 and 3. The map in
slide #15 calls these zones 4, 5 and 6.
Slide 19 is referring to RTF zones 2 and 3.
Steve Johnson: So a BTU of natural gas is about one third the cost of a BTU of
electricity? Yes.
Jørgen Rasmussen: But are they CO2 equivalent? Doesn’t Kendall Yards [Spokane
housing development near downtown] have all heat pumps? Not all. There are one or
two heat pumps per condo and the rest are resistance heat.
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Pauline Drury: Sounds like CO2 heat pumps are something for reducing heat. Is this for
the source of electricity because I have a personal feeling that we should be reducing
carbon? These are CO2 heat pumps that use CO2 in the system.
Jørgen Rasmussen: Greenhouse gas free because CO2 is less potent than other
refrigerants.
Gerry Snow: More penetration of renewables makes the power budget (E&G) move to
electrification, like British Columbia, and even more extreme as hydrogen in natural gas
pipes. Where is the trade off? If it’s a capacity issue, more storage is better.
Resource Adequacy and Effective Load Carrying Capability, James Gall
Steve Johnson: Balancing area has performance standards. Different kind of things.
Obligations to meet load within the house. NPCC quote.
Steve Johnson: You don’t model natural gas fuel disruptions? No, we don’t assume
pipeline or storage disruptions. This study is not cost, just availability.
Steve Johnson: Power Council, couldn’t you just get something from another. We have
a winter problem.
Amy Wheeless: Becoming more summer peaking regionally. Yes and no. Summer is
more consistent than winter.
Steve Johnson: Don’t have a good way of moving up summer or winter temperatures to
set “benefits” of global warming for resource adequacy. The means are changing, but
the extremes not so much.
James Gall: Wind improves reliability, but not by as much as thought. There is lots of
variation site-to-site so more work is needed to pick the right number to use for reliable
wind capacity – 5 to 10% range is probably right.
Clint Kalich: Does the Power Council still use 5% for wind?
Mike Starrett: Northwest capacity contribution for Columbia Gorge wind is 3% on its
own, 9.5% when integrated with hydro. Solar is 3% and higher when integrated.
Steve Johnson: Their model accounts for energy at night allowing more daytime hydro.
Avista’s model does too.
James Gall: Need to consider correlation with very low temperatures in Montana
compared to us. So we need more studies. Solar helps a little bit at 2.2% by moving
hydro and if we peak in February. We had one of our last peaks with zero wind and
solar for a week. This study considers demand response at 10 times per year now,
ELCC (Effective Load Carrying Capability) would go up if there were more times per
year.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 208 of 1057
Steve Johnson: Is the curve used to develop the LOLP (loss of load probability)
accurate? Yes, if want to use renewables to back up LOLP, need to add multiples of the
renewable resources to get a better chance they are available when needed. Learned
from the past model.
Amy Wheeless: Why not reduce gas more?
James Gall: Storage moves and loses energy. The losses vary by the type of storage
like lithium ion or hydrogen. Storage needs to be paired with something to charge it.
Matt Nykiel: Does this include carbon (cost)? No, but about 5 times more expensive.
Clint Kalich: About 6 times. This is for peaking capacity, so only runs about 5 percent of
the time for reliability or low hydro conditions.
Mike Starrett: I have some questions about the numbers in the slides that can’t be
shown online.
Steve Johnson: Diversity – Avista could build a whole bunch and pay full cost while
helping everyone else. It’s great to think of one big utility, but we don’t share the fixed
costs.
Clint Kalich: Today, we are already long as a region. This is an additional surplus
needed to charge these batteries. At a certain point, it doesn’t help more. Is this
incremental energy? This is how much wind and storage is needed to help.
Mike Starrett: More midday curtailment. Policy changes a little bit later. In Aurora, are
those resources being curtailed so that adding more renewables lowers the value of
them?

2019 Electric IRP Key Case Assumptions
Steve Johnson: Fully electric percentage? (Slide #9, Electric Vehicles) We don’t have
the all-electric percentages broken out. Rendall Farley might. There is less separation
between all-electric EVs and plug-in hybrids.
Steve Johnson: Looking at the causal effect, if all these things are different, volatility
may be different for loads, uses, etc.
Steve Johnson: Not a normal distribution? No, it isn’t.
Jennifer Snyder: BPA has a forward looking study for hydro conditions (due to climate
change). Briefly, Avista expects the same amount of water for hydro, but the timing of it
moves from the spring to the winter based on the studies we have reviewed.
Garret Brown: Was the last hydro year good? Hydro was really good the first six months
and worse the rest of the year. About 5% lower regionally, but Avista did better than the
regional average.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 209 of 1057
Matt Nykiel: What is the time frame for coal prices deadline to comment? Proposals in
February, comment deadline a week or so after the next TAC meeting [February 6] and
scenarios could be a few weeks later.
Steve Johnson: Not sure of not doing a risk analysis for climate changes to hydro.
Mike Starrett: BPA came in and did a presentation last meeting (Power Council) and in
person to the council. Is it a sensitivity or not? More winter rain, so a shortage from
winter to summer.
Steve Johnson: You have examples of what it looks like when it warms. You could do a
scenario or something like a single year look at it.
Rachelle Farnsworth: How do you include the risk associated with Colstrip? We have a
slide for that.
Steve Johnson: There will be a different value for renewables before and after
greenhouse gas prices. The shadow price is not going down much.
Clint Kalich: But people who waited and bought after I-937 paid less.
Matt Nykiel: No one wants to pay $20 per dekatherm, but there is a cost.

Futures and Scenarios, James Gall and John Lyons
Jennifer Snyder: I would be more comfortable using 2020 instead of 2025 (for the start
date of carbon pricing).
Steve Johnson: Another approach setting an objective function with an objective
function.
Steve Johnson: We should probably set up a meeting with Brad (Cebulko) and others to
go through this.
Matt Nykiel: Why only Washington? It was for a WUTC request. A later slide shows a
scenario for all of Avista’s service territory.
Steve Johnson: Look at the Northwest Natural IRP for their natural gas price for any
divergent numbers.
Steve Johnson: Will you include the updated forced outage rates for Colstrip? Yes, we
will use the most recent forced outage rates.
Matt Nykiel: Changes in ownership structure in Colstrip Units 3 and 4.
Steve Johnson: If not operating, an exit provision.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 210 of 1057
Steve Johnson: You should make sure to have a letter shielding any employees with
knowledge of what would be paid in the future for the ownership interest in Lancaster.
Avista Corporation sold its ownership interest in Lancaster in 2006.
Public Counsel (phone): Is the social cost of carbon included in its own case? It is one
of three futures, treated at the same time.
Amy Wheeless: Spreadsheet available by the end of the week or early next week? Yes.
Matt Nykiel: Will there be a breakdown of basic assumptions for Colstrip? Costs and
when they are expected to occur.
Matt Nykiel: What happens if someone walks away (from Colstrip), can you show how
costs get reapportioned? Would need to check on what could happen.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 211 of 1057
2020 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Tuesday, April 16, 2019 Avista Headquarters, Conference Room 130

Topic Time Staff Introductions and TAC 2 Recap 9:00 Lyons

Regional Legislative Update 9:10 Lyons

IRP Transmission Planning Studies 9:30 Rolstad

Break 10:30 Distribution Planning Within the IRP 10:45 Fisher Lunch 12:00 Conservation Potential Assessment 1:00 AEG

Demand Response Potential Assessment 2:00 AEG

Break 3:00 Pullman Smart Grid Demonstration Project 3:15 Doege Review E3 Study – Resource Adequacy in the Pacific 3:45 Gall
Northwest

Adjourn 4:30
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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2019 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
November 27, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 213 of 1057
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington every other year
•Guides resource strategy over the next two 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
2
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Schedule 1a, Page 214 of 1057
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 in all or some of the process
•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 studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 215 of 1057
TAC #2 Recap –November 27, 2018
•Introductions and TAC 1 Recap, Lyons
•Modeling Process Overview, Gall
•Generation Resource Options, Gall
•Home Heating Technologies Overview, Lienhard
•Resource Adequacy and Effective Load Carrying
Capability, Gall
•Key Assumptions, Gall and Lyons
•Futures and Scenarios, Gall and Lyons
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-
company/integrated-resource-planning
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Updates –Rattlesnake Flat Wind PPA
•Issued RFP June 6, 2018 to capture low renewables pricing
resulting from expiring PTC and ITC
•Bids for over 2,000 MW from 40 wind and solar offers
•9/19/18: 150 MW Rattlesnake Flat Wind (Clearway Energy)
•Contract signed March 7, 2019
•Construction begins May 2019 and scheduled to be online 12/31/20
•About 12 miles southeast of Lind, Washington on 20,000 acres
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Rattlesnake Flat Wind Project
6
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Today’s Agenda
•9:00 –Introductions and TAC 2 Recap, Lyons
•9:10 –Regional Legislative Update, Lyons
•9:30 –IRP Transmission Planning Studies, Rolstad
•10:30 – Break
•10:45 –Distribution Planning within the IRP, Fisher
•Noon –Lunch
•1:00 –Conservation Potential Assessment, AEG
•2:00 –Demand Response Potential Assessment, AEG
•3:00 – Break
•3:15 –Pullman Smart Grid Demonstration Project, Doege
•3:45 –Review E3 Study –Resource Adequacy in the Pacific
Northwest, Gall
•4:30 –Adjourn
7
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TAC 4 Topics
•TAC 4 on Tuesday, August 6, 2019
–Natural Gas Price Forecast
–Electric Market Forecast
–Energy and Peak Load Forecast
–Existing Resource Overview (Colstrip, Lancaster, and
other resources)
–Final Resource Needs Assessment
•TAC 5: Tuesday, October 15, 2019
•TAC 6: Tuesday, November 19, 2019
8
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2019 Electric IRP
Regional Legislative Update
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
April 16, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 221 of 1057
Washington Legislation
•SB 5981: Greenhouse gas emissions cap and trade program
–Public hearing held on March 21 in the Senate Environment, Energy and
Technology Committee. No further action scheduled.
•HB 1257: Energy efficient buildings and natural gas conservation
–Governor requested for new conservation requirements for natural gas utilities by
setting energy performance standards for commercial buildings and utility
administered incentive program for early energy performance retrofits. Authorizes
utilities to propose renewable natural gas (RNG) procurement program and
voluntary RNG tariffs. Passed House 3/29/19 and put on Senate Floor calendar.
•HB 1444: Appliance efficiency standards
–Department of Commerce requested minimum efficiency and testing standards
for certain appliances. Passed House 3/5/19 and on Senate Floor calendar.
•HB 1512: Electrification of transportation
–Allows electrification of transportation plan and incentives. Passed both
chambers.
•HB 1126 Distributed resource planning
–Declare state policy that utility DER planning process accomplish certain goals
and require Legislature to conduct an initial review of the state's policy by
January 1, 2023. 2
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Washington SB 5116 Clean Electricity Bill
•Governor’s clean electricity bill –100 percent carbon neutral by
2030
•Eliminates coal-fired electricity serving Washington customers by
12/31/25,
•100 percent carbon neutral resources by 2030
•Eliminating use of fossil-fuel generation to serve Washington load
beginning in 2045
•Passed Senate and House, back to Senate to approve House
changes
•2% annual cost cap
•Must consider the social cost of carbon for conservation evaluation
and selection, developing IRP and clean energy plans, and
evaluating and selecting intermediate and long-term resources
3
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Idaho and Montana Updates
Idaho: No major legislative proposals impacting the IRP
Montana:
•SB 331: Allow preapproval of 150 MW additional from Colstrip unit 4
for NorthWestern. Passed Senate.
•SB 201: revise requirements to hold mine permits to make sure
Rosebud Mine pensions are paid. Passed House and Senate.
•SB 252: Revise Montana Facility Siting Act to allow a coal mining
permit owner to get coal from outside of the Rosebud Mine. Passed
and back to Senate with amendments.
•HB 476:low interest loans from Montana Board of Investment for
NorthWestern to acquire additional interest in Colstrip and Talen to
replace coal supply agreement. Passed House and Senate.
•SB 189: Carbon Tax bill tabled.
4
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Oregon Update
HB 2020: Greenhouse gas cap and trade
•Establishes a cap and trade program for entities with 25,000 tons or
more of greenhouse gas emissions. Creates the Carbon Policy
Office within Oregon Department of Administrative Services and
directs the Director of Carbon Policy Office to adopt Oregon Climate
Action Program by rule.
5
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IRP Transmission Planning Studies
Tracy Rolstad, Transmission Planning
Third Technical Advisory Committee Meeting
April 16, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 226 of 1057
Education
•Tracy Rolstad
–Diploma, Naval War College, College of Naval
Command and Staff
–BSEE, University of Idaho
–Nuclear Navy
•Nuclear Operational Prototype (S1C)
•Nuclear Power School (Reactor Operator)
•Electronics Technician School
–Radar, Communications, etc.
–Professional Technical Education
•Too numerous to list…
2
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Resume…
–Avista Corporation
•Senior Pwr Sys Consultant, System Planning
•WECC DS Chair, WECC TSS Chair
–Utility System Efficiencies
•Senior Power Systems Analyst
–The Bonneville Power Administration
•Senior Engineer, System Operations
–The Joint Warfare Analysis Center
•EP Senior Analyst, PACOM Chief of Targets
•Special Technical Operations Action Officer
–Nuclear Navy (Attack Submarines)
•Chief Petty Officer (ETC/SS)
•Engineering Watch Supervisor
3
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Something Novel About Me
4
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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 (OASIS is the place where this
information is made public)
5
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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
6
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Introduction to Avista System Planning
Avista’s System Planning Group includes:
•Transmission Planning
•Distribution Planning
•And we all care about:
–Federal, regional, and state compliance
–Regional system coordination
–Reliable electric service
•We provide transmission service
–To anyone
–To any type of generation or load
•We are ambivalent about type (must perform though)
7
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Information About Transmission Planning
•We care about the Bulk Electric System (BES)
–Our 115 kV and 230 kV facilities (>100 kV)
•If the Avista BES looks like it won’t reliably
deliver electrons to our customers in the near or
distant future, we 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
8
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TPL-001-4
•Describes outages we must study
–P0: everything online and working
–P1: single facility outages, like a transformer
–P2 to P5: increasing levels of outages
–P6: any combination of two facilities
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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TPL-001-4
•A couple of NERC directives for the faults above
–“The System shall remain stable”
–“Applicable Facility Ratings shall not be exceeded”
–“An objective of the planning process is to minimize
the likelihood and magnitude of Non-Consequential
Load Loss following planning events”
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Two Approaches to Reliability Issues
•Transmission Operators (TO) are guided by
significantly different standards than
Transmission Planners (TP).
•TO standards provide flexibility that TP
standards do not allow
–Operators can do anything to SAVE the
interconnected system
•Planners hopefully give them the tools to do this
–We HAVE changed our ways since 2007 (NERC stds)
»Inverse dog years are utility years
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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We Are Recovering From This…
A quote from the late 90’s: “That’s our stuff, we will take the hit and shed load if needed.”
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Recent Transmission Projects
13
Benton –Othello 115 kV Rebuild (still ongoing)
Westside xfmr replacement/station rebuild
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Non Wires (or perhaps no new wires)
•Avista made “non-wires” Columbia Grid
workshop happen (held at PSE HQ)
14
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Non Wire Solutions are always evaluated
•We are documenting this with more clarity
•Non wires REQUIRE robust wires to perform
–Smartwire evaluation (our wires are too small!)
•Avista is working on the transmission fundamentals
15
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New wires…same footprint
•Small wire replacement
–Mostly copper replacement
•Facilitates use of SmartWires technology
–But practically eliminates the need in the near term
»It DOES literally physical support the devices…
Avista Planning has been studying these
since 2015. Partnered with U of I as well
sponsoring R&D on DFACTS
ACSS @ 200C
tremendous ratings
-or-Trap Wire…
16
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Evaluated Batteries for T-1-1
•TPL-001-4 T-1-1 Evaluation
–Double transformer outages
•Shawnee 230/115 kV
–Concurrent with outage of Moscow 230/115 kV
•Could we mitigate performance issues with storage?
–Yes…but…
»We would need a 100 MW battery
•Charge is 8 hours, discharge for 12 to 16 hours
•A third transformer is a better solution
•Robust performance and much less $$$$
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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
18
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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2019 IRP TransmissionCost Estimates
Station Request (MW)POI Voltage Cost Estimate ($ million)
Kootenai County (GF)100 230 kV 2
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%19
RAS changes
everything!
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Current Queue
20
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Monroe Street: 80 MW
21
•3 miles of 115 kV
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Post Falls: 10 MW to 20 MW
22
•Interconnection Only
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Questions?
Avista OASIS link:
http://www.oasis.oati.com/avat/index.html
23
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Electric Distribution Within the IRP
Damon Fisher, System Planning
Third Technical Advisory Committee Meeting
April 16, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 249 of 1057
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
•Voltage, Power Quality, etc.
–Operational flexibility
–Meet Corporate/Regulatory goals
2
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North Spokane Study
3
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Study Area Map
4
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Total Area Demand 8/10/18
5
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Feeder Demand 8/10/18
6
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Add two 5MW 6 Hour Batteries
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Feeder Demand with Batteries
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Modest Solar Installation
9
Assumes addition of 1.5 MW of solar per feeder
or 9 MW total solar capacity Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 257 of 1057
Perspective ~ 4MW 4 Hour Battery vs.
60MW 8,760 Hour Substation
200ft
Substation/Transmission- $5 Million
Batteries (10MW with 6 hours)-~$25 Million
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Distribution Battery Benefits
–Peak shaving
–Outage remediation (Islanded)
–Operational flexibility (back up a feeder)
–Generation shifting
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 259 of 1057
Other Projects
•New Flint Road Substation
–Offload overloaded feeders in Airway Heights
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 260 of 1057
Other Projects
•Huetter Road Substation
–Offload overloaded feeders in Coeur d’Alene
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 261 of 1057
Other Projects
•New Colbert Substation
–Offload overloaded Colbert Feeders
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Conclusion
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Questions?
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Energy solutions. Delivered.
2018 ELECTRIC CPA RESULTS SUMMARY
Prepared for Avista Energy
April 5, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 265 of 1057
| 2Applied Energy Group · www.appliedenergygroup.com
AGENDA
Topics
AEG Introduction
Approach
Summary of Findings
Comparison with 2016 Potential Study
DR Analysis
Supplemental Slides
Sector-Level Results
Summer DR Impacts
Standalone DR Analysis Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 266 of 1057
| 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 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 Energy*BPA*Cascade Natural GasChelan PUDCheyenne LFPColorado Electric*Cowlitz PUD*Avista*
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Approach
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 6Applied Energy Group · www.appliedenergygroup.com
OverviewOVERVIEW 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
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 in this study
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 7Applied 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
•Customer Account Database
•Forecast data and load research
•Recent-year accomplishments and plans
•NEEA studies (RBSA 2016, CBSA 2014, 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 8Applied 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 choosesefficient option when equipment fails
•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
•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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 9Applied Energy Group · www.appliedenergygroup.com
New Activities for 2019 IRP
From the Avista 2017 Electric IRP Acknowledgement Attachment (UE-161036):
In its comments in this docket, Commission Staff wrote that it has concerns with how the Company performs its conservation potential assessment (CPA), such as the Company’s exclusion of conservation measures from the CPA prior to determining its technical potential.16 We share Staff’s concern. It is critical that the Company achieve all cost-effective conservation, not only because this is required under the Energy Independence Act, but also because conservation and efficiency resources are the foundation of a least-cost resource stack.
In its 2019 IRP, the Company must ensure the entity performing the CPA evaluates and includes the following information:
1.All conservation measures excluded from the CPA, including those excluded prior to technical potential determination.
2.The rationale for excluding any measure.
3.A description, and source, of Unit Energy Savings data for each measure included in the CPA.
4.An explanation for any differences in economic and achievable potential savings.
The Company should also share its proposed energy efficiency measure lists with the Conservation Advisory Group prior to completing the CPA.
•Determine whether or not to move the T&D benefits estimate to a forward looking value versus a historical value.
•Determine if a study is necessary to estimate the potential and costs for a winter and summer residential demand response program and along with an update to the existing commercial and industrial analysis.
•Use the utility cost test methodology to select conservation potential for Idaho program options.
2017-2018 ACTION PLAN
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 10Applied Energy Group · www.appliedenergygroup.com
Exclusions from CPA
Recommended Activity:
In the 2019 IRP, ensure that the entity performing the Conservation Potential
Assessment (CPA) evaluates and includes the following information:
•All conservation measures excluded from the CPA, including those excluded prior
to technical potential determination;
•Rationale for excluding any measure;
•Very few measures were excluded from the current CPA prior to estimation of
technical potential. Those explicitly excluded were:
Some emerging tech measures where available cost or savings data was insufficient for characterization
Highly custom commercial and industrial controls/process measures that were instead captured under a retrocommissioning or strategic energy management program
•Measures that did not pass the economic screen were still counted in within achievable technical potential, allowing Avista to review for inclusion in programs if
portfolio-level cost-effectiveness allows.
MEASURE SCREENING
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 11Applied Energy Group · www.appliedenergygroup.com
Documentation of Savings and Other Assumptions
Recommended Activity:
•Description of Unit Energy Savings (UES) for each measure included in the CPA; specify how it was derived and the source of the data;
•The measure list developed during the CPA includes descriptions of each measure included. AEG will provide this as an appendix to the final report.
•Source documentation for assumptions, including UES, lifetime, and costs
(including NEIs) may be found in the “Measure Summary” spreadsheet delivered as an appendix to the final report.
This will include the name of the source and version (if applicable)
MEASURE DOCUMENTATION
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 12Applied Energy Group · www.appliedenergygroup.com
Explanation of Difference between Achievable and Economic
Recommended Activity:
•Provide an explanation for any differences in economic and achievable potential savings.
•Use the utility cost test methodology to select conservation potential for Idaho program options
•This round of the CPA delivers the full Achievable Technical potential for all
measures along with the associated TRC and UCT levelized costs ($/MWh) for each measure.
Avista’s IRP process will then perform its own economic considerations
•As both TRC and UCT levelized costs are provided, Idaho potential can be
evaluated using UCT costs as recommended.
ECONOMIC POTENTIAL
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 13Applied Energy Group · www.appliedenergygroup.com
Assess Potential Value of Summer Peak and Residential
Recommended Activity:
•Determine if a study is necessary to estimate the potential and costs for a winter and summer residential demand response program and along with an
update to the existing commercial and industrial analysis.
•The DR analysis included Summer as well as winter impacts, and Residential
program options, so that Avista will have the needed data to evaluate possible program combinations for DR
DEMAND RESPONSE
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Summary of Findings
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 15Applied Energy Group · www.appliedenergygroup.com
Potential Summary –WA & ID All SectorsENERGY EFFICIENCY POTENTIAL
Projections indicate that energy savings of ~1.1% of baseline consumption per year are Technically Achievable.
•152 GWh (17 aMW) in biennium period (2021-2022)
•976 GWh (111 aMW) by 2030
•This level of savings offsets future load growth
-
2,000
4,000
6,000
8,000
10,000
12,000
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
0
50
100
150
200
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
Annual Incremental Potential
Technical Achievable Potential (GWh)Technical Potential (GWh)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 16Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –WA & ID, All Sectors
Summary of Energy Savings (GWh), Selected
Years 2040
Reference Baseline (GWh)8,291.9 8,334.1 8,518.5 8,994.6 10,375.9
Cumulative Savings (GWh)
Technical Achievable Potential 71.4 151.6 439.3 976.3 1,973.7
Technical Potential 156.1 310.2 777.4 1,505.6 2,490.1
Energy Savings (% of Baseline)
Technical Achievable Potential 0.9%1.8%5.2%10.9%19.0%
Technical Potential 1.9%3.7%9.1%16.7%24.0%
Incremental Savings (GWh)
Technical Achievable Potential 71.4 81.1 108.4 114.4 102.4
Technical Potential 156.1 155.6 165.5 145.7 87.2
0%
5%
10%
15%
20%
25%
30%
2021 2022 2025 2030 2040
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
-
500
1,000
1,500
2,000
2021 2024 2027 2030 2033 2036 2039
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 17Applied Energy Group · www.appliedenergygroup.com
Cumulative Potential Summary –WA & ID All SectorsEE POTENTIAL -TOP MEASURES
Technical Achievable Potential, Ranked by Savings in 2030 (MWh)
Low Cost
Rank
2022 Achievable
Technical Potential
Savings (MWh)
2030 Achievable
Savings (MWh)
1 -Linear Lighting
2 -Ductless Mini Split Heat Pump (Ducted Forced Air)
3 -High-Bay Lighting
4 -Ductless Mini Split Heat Pump (Zonal)
5 -Water Heater (<= 55 Gal)
6 -Area Lighting
7 -ENERGY STAR Home Design
8 -Thermostat -Connected
9 -Windows -Cellular Shades
10 -Advanced New Construction Design -Zero Net Energy
11 -Dishwasher
12 -Water Heater -Low-Flow Showerheads
13 -General Service Screw-in
14 -Ventilation
15 -Space Heating -Heat Recovery Ventilator
16 -High-Bay Lighting
17 -Refrigeration -Evaporative Condenser
18 -Monitor
19 -Windows -Low-e Storm Addition
20 -RTU
Total of Top 20 Measures 51,000.4 33.65%480,369.0 49.21%
Total Cumulative Savings 151,553.0 100.00%976,256.8 100.00%
High Cost Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 281 of 1057
| 18Applied 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
•Highlighted in orange on previous slide
•Heat Pump measures, including DHPs and HPWHs, have significant
energy benefits, however since heat pumps revert to electric resistance
heating during extreme cold, they have no effect on winter peak
•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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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| 19Applied Energy Group · www.appliedenergygroup.com
Top Measures -Winter Peak (MW)
Reduction by 2030
2030
MW
% of
Total
1 Commercial -Linear Lighting 6.5 6.2%
2 Residential -ENERGY STAR Home Design 5.8 5.5%
3 Commercial -High-Bay Lighting 4.9 4.7%
4 Residential -Thermostat -Connected 4.7 4.4%
5 Residential -Windows -Cellular Shades 3.9 3.7%
6 Commercial -Space Heating -Heat Recovery
Ventilator 3.3 3.1%
7 Residential -Advanced New Construction Design -
Zero Net Energy 2.8 2.6%
8 Residential -General Service Screw-in 2.5 2.4%
9 Residential -Insulation -Floor Installation 2.5 2.3%
10 Residential -Water Heater -Low-Flow
Showerheads 2.4 2.3%
11 Residential -Windows -Low-e Storm Addition 2.2 2.1%
12 Industrial -Destratification Fans (HVLS)2.0 1.9%
13 Residential -Building Shell -Infiltration Control 2.0 1.9%
14 Industrial -High-Bay Lighting 1.9 1.8%
15 Residential -Dishwasher 1.8 1.7%
16 Residential -Insulation -Wall Cavity Installation 1.7 1.6%
17 Residential -Ducting -Repair and Sealing 1.6 1.5%
18 Commercial -Commissioning 1.5 1.4%
19 Commercial -Interior Lighting -Networked Fixture
Controls 1.4 1.3%
20 Commercial -Destratification Fans (HVLS)1.3 1.2%
Total of Top Measures 56.5 53.5%
Total Technical Achievable Reduction (MW)105.6 100.0%
Peak Impacts –Technical Achievable Potential
Top Measures -Summer Peak (MW)
Reduction by 2030
2030
MW
% of
Total
1 Residential -Ductless Mini Split Heat Pump
(Ducted Forced Air)5.2 5.4%
2 Residential -Water Heater (<= 55 Gal)5.2 5.4%
3 Commercial -Linear Lighting 5.0 5.2%
4 Commercial -High-Bay Lighting 3.8 4.0%
5 Residential -Water Heater -Low-Flow
Showerheads 3.1 3.3%
6 Commercial -RTU 2.9 3.0%
7 Residential -ENERGY STAR Home Design 2.6 2.7%
8 Residential -Dishwasher 2.5 2.6%
9 Commercial -RTU -Advanced Controls 2.4 2.5%
10 Residential -Advanced New Construction Design -
Zero Net Energy 2.3 2.4%
11 Industrial -High-Bay Lighting 2.2 2.3%
12 Residential -General Service Screw-in 1.9 2.0%
13 Residential -Monitor 1.6 1.6%
14 Residential -Freezer -Decommissioning and
Recycling 1.5 1.5%
15 Commercial -Chiller -Variable Flow Chilled Water
Pump 1.5 1.5%
16 Commercial -RTU -Evaporative Precooler 1.5 1.5%
17 Residential -Advanced Power Strips -IR Sensing 1.4 1.4%
18 Commercial -Commissioning 1.2 1.3%
19 Residential -Stove/Oven 1.1 1.2%
20 Residential -Refrigerator -Decommissioning and
Recycling 1.1 1.2%
Total of Top Measures 50.1 52.1%
Total Technical Achievable Reduction (MW)96.0 100.0%
EE POTENTIAL -CONTINUED
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 283 of 1057
| 20Applied Energy Group · www.appliedenergygroup.com
WA & ID Technical Achievable Potential by 2030SUPPLY 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, 2030
Technical Potential Technical Achievable 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, 2030
Technical Potential Technical Achievable Potential Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 284 of 1057
| 21Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Washington, All Sectors
Summary of Energy Savings (GWh), Selected
Years 2040
Reference Baseline (GWh)5,243.2 5,268.4 5,381.1 5,686.8 6,571.8
Cumulative Savings (GWh)
Technical Achievable Potential 47.2 100.0 288.5 636.5 1,272.0
Technical Potential 102.5 203.4 508.2 979.2 1,607.3
Energy Savings (% of Baseline)
Technical Achievable Potential 0.9%1.9%5.4%11.2%19.4%
Technical Potential 2.0%3.9%9.4%17.2%24.5%
Incremental Savings (GWh)
Technical Achievable Potential 47.2 53.4 71.1 74.0 64.7
Technical Potential 102.5 101.9 108.1 94.2 54.9
0%
5%
10%
15%
20%
25%
30%
2021 2022 2025 2030 2040
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
-
200
400
600
800
1,000
1,200
1,400
2021 2024 2027 2030 2033 2036 2039
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 285 of 1057
| 22Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Idaho, All Sectors
Summary of Energy Savings (GWh), Selected
Years 2040
Reference Baseline (GWh)3,048.7 3,065.7 3,137.4 3,307.8 3,804.1
Cumulative Savings (GWh)
Technical Achievable Potential 24.2 51.6 150.7 339.8 701.7
Technical Potential 53.6 106.8 269.2 526.3 882.8
Energy Savings (% of Baseline)
Technical Achievable Potential 0.8%1.7%4.8%10.3%18.4%
Technical Potential 1.8%3.5%8.6%15.9%23.2%
Incremental Savings (GWh)
Technical Achievable Potential 24.2 27.6 37.4 40.4 37.7
Technical Potential 53.6 53.7 57.4 51.5 32.4
-
200
400
600
800
1,000
1,200
1,400
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
2021 2022 2025 2030 2040
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 286 of 1057
Comparison with 2016 Potential Study
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 287 of 1057
| 24Applied 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
•E.g. lighting potential in 2019 and 2021 is very different
Since we are no longer estimating potential in 2017-2020, potential for those years must be removed from the comparison
•First-Year Incremental Potential -2021
Prior Study: 4th year of potential
Current Study: first year
This reduces potential since it accounts for two extra high-UES lighting years before EISA
The previous study’s 20-year look ended in 2037, therefore we must remove2038-2040 from the comparison
•Cumulative Potential Comparisons –2021 through year 2036
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 17 year comparison (2021-2037)
NOTES ON COMPARISON
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 288 of 1057
| 25Applied Energy Group · www.appliedenergygroup.com
ACHIEVABLE POTENTIAL COMPARISONComparison with Prior Potential Study (2021-2037 TAP)
0
200
400
600
800
1000
1200
2018 2019 2022 2027 2037
GWh
Idaho All-Sector TAP Comparison
Prior Study (2018-2020)
Prior Study (2021-2037)
Current Study
0
200
400
600
800
1000
1200
2018 2019 2022 2027 2037
GWh
Washington All-Sector TAP Comparison
Prior Study (2018-2020)
Prior Study (2021-2037)
Current Study
Sector
(All States)End Use
Prior CPA
2037 MWh
Current
Study 2037
MWh Diff.
Residential
Cooling 44,269 63,188 18,919
Heating 242,917 366,549 123,632
Water Heating 191,988 206,932 14,944
Interior Lighting 43,555 55,064 11,509
Exterior Lighting 8,102 10,986 2,884
Appliances 72,894 76,363 3,469
Electronics 39,573 47,688 8,115
Miscellaneous 8,910 24,586 15,676
Commercial
Cooling 108,883 100,887 -7,996
Heating 53,198 46,496 -6,702
Ventilation 73,836 60,660 -13,176
Water Heating 11,199 23,150 11,951
Interior Lighting 225,353 270,791 45,438
Exterior Lighting 81,887 100,530 18,643
Refrigeration 21,665 63,885 42,220
Food Preparation 23,287 23,200 -87
Office Equipment 25,305 11,713 -13,592
Miscellaneous 322 2,091 1,770
Industrial
Cooling 6,303 5,455 -849
Heating 4,370 11,528 7,158
Ventilation 6,472 5,775 -697
Interior Lighting 22,925 40,131 17,206
Exterior Lighting 9,500 10,952 1,452
Motors 122,296 47,316 -74,980
Process 14,848 9,987 -4,860
Miscellaneous 1,665 566 -1,099
Grand Total 1,465,522 1,686,470 220,948Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 289 of 1057
| 26Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIAL
Washington -Comparison with Prior Study –Technical Achievable
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2021 2025 2029 2033 2037
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
2021 2025 2029 2033 2037
MWh
Commercial
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2021 2025 2029 2033 2037
MWh
Industrial
Prior Study
Current Study
•2018-2020 already removed from
prior study values
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 290 of 1057
| 27Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIALIdaho -Comparison with Prior Study –Technical Achievable
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2021 2025 2029 2033 2037
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2021 2025 2029 2033 2037
MWh
Commercial
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
2021 2025 2029 2033 2037
MWh
Industrial
Prior Study
Current Study
•2018-2020 already removed from
prior study values
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 291 of 1057
| 28Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study –Technical Achievable
Residential:
•Potential reduced due to RTF “Market Baseline” assumption substantially lowering screw-in lighting savings
•DOE expanded definition of “General Service” now includes reflectors, reducing exempted lighting potential
•Idaho residential has extra potential in emerging New Construction measures (less impactful in WA due to the strict energy code)
However these measures are very expensive and unlikely to be selected by IRP
•Increases in lighting potential primarily due to new linear and high-bay lighting technology combination with integrated fixture controls
•Decreases in weatherization, particularly in WA, reflecting continuing influence of building codes and construction trends
•Removed key large accounts from WA Industrial control totals so as not to treat these singular entities as an “average population” that would have regular ramp-up and measure installations
SECTOR-LEVEL NOTES
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 292 of 1057
DR Potential Results
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 293 of 1057
| 30Applied Energy Group · www.appliedenergygroup.com
Annual Winter Peak MW, Two ScenariosOVERALL PROJECTION
Winter Peak MW 2021 2022 2025 2030 2040
Baseline Projection
Market Potential
Potential (% of baseline)
Potential Projection -
500
1,000
1,500
2,000
MW
Baseline Forecast Potential Forecast
Summer Peak MW 2021 2022 2025 2030 2040
Baseline Projection
Market Potential
Potential (% of baseline)
Potential Projection -
500
1,000
1,500
2,000
MW
Baseline Forecast Potential Forecast
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 294 of 1057
| 31Applied Energy Group · www.appliedenergygroup.com
By 2040, by State and Option, TOU Opt-in ScenarioWINTER PEAK MW REDUCTIONS
Winter Potential in 2040 ID WA Grand
Total
DLC
DLC Central AC 0.00 0.00 0.00
DLC Water Heating 6.88 12.38 19.27
DLC Smart Thermostats -Cooling 0.00 0.00 0.00
DLC Smart Thermostats -Heating 7.14 12.60 19.74
DLC Smart Appliances 1.24 2.21 3.45
DLC Electric Vehicle Charging 0.39 0.74 1.14
Third Party Contracts 8.47 14.78 23.25
Rates
Time-of-Use Opt-in 2.47 4.72 7.20
Time-of-Use Opt-out
Variable Peak Pricing Rates 7.48 14.00 21.48
Real Time Pricing 0.21 0.38 0.58
Ancillary Services 0.93 1.55 2.48
Thermal Energy Storage 0.00 0.00 0.00
Battery Energy Storage 1.87 3.34 5.21
Behavioral 1.07 2.08 3.15
Grand Total 38.16 68.78 106.95
0 5 10 15 20 25
DLC Central AC
DLC Water Heating
DLC Smart Appliances
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating
DLC Electric Vehicle Charging
Third Party Contracts
Time-of-Use Opt-in
Time-of-Use Opt-out
Variable Peak Pricing Rates
Real Time Pricing
Ancillary Services
Thermal Energy Storage
Battery Energy Storage
Behavioral
Achievable Potential (MW)
Winter DR Potential in 2040
ID WA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 295 of 1057
| 32Applied Energy Group · www.appliedenergygroup.com
By 2040, by State and Option, TOU Opt-in ScenarioSUMMER PEAK MW REDUCTIONS
Summer Potential in 2040 ID WA Grand
Total
DLC
DLC Central AC 2.85 4.92 7.78
DLC Water Heating 6.88 12.38 19.27
DLC Smart Thermostats -Cooling 1.24 2.21 3.45
DLC Smart Thermostats -Heating 2.94 5.06 8.00
DLC Smart Appliances 0.00 0.00 0.00
DLC Electric Vehicle Charging 0.39 0.74 1.14
Third Party Contracts 7.64 13.23 20.87
Rates
Time-of-Use Opt-in 2.35 4.58 6.93
Time-of-Use Opt-out 0.00 0.00 0.00
Variable Peak Pricing Rates 7.10 13.59 20.69
Real Time Pricing 0.19 0.33 0.52
Ancillary Services 0.85 1.40 2.25
Thermal Energy Storage 0.32 0.48 0.80
Battery Energy Storage 1.87 3.34 5.21
Behavioral 1.03 2.05 3.08
Grand Total 35.64 64.34 99.98
0 5 10 15 20 25
DLC Central AC
DLC Water Heating
DLC Smart Appliances
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating
DLC Electric Vehicle Charging
Third Party Contracts
Time-of-Use Opt-in
Time-of-Use Opt-out
Variable Peak Pricing Rates
Real Time Pricing
Ancillary Services
Thermal Energy Storage
Battery Energy Storage
Behavioral
Achievable Potential (MW)
Summer DR Potential in 2040
ID WA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 296 of 1057
Comparison with 2016 Potential Study
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 297 of 1057
| 34Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study
There were several changes made to the previous DR Potential Study:
•Included Summer Peak in analysis
•This presentation will focus on Winter Potential only to directly compare to the previous study
•Included Residential Sector in analysis
•Changes to Measure Options this year:
•Critical Peak Pricing Variable Peak Pricing
•Firm Curtailment Third Party Contracts
•Prioritized Smart Thermostats over Space Heating Switches
•Note: Comparison between calendar years for DR does not remove previous year impacts like the EE comparison
NOTES ON COMPARISON
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 298 of 1057
| 35Applied Energy Group · www.appliedenergygroup.com
DR POTENTIAL COMPARISON OPT-INComparison with Prior Potential Study by State (
-
5.0
10.0
15.0
20.0
25.0
30.0
35.0
2021 2025 2029 2033 2037
MW
Washington Opt-In Comparison
Prior Study
Current Study C&I
-
5.0
10.0
15.0
20.0
25.0
30.0
35.0
2021 2025 2029 2033 2037
MW
Idaho Opt-In Comparison
Prior Study
Current Study C&I
Notes on comparison:
•2021 values for Prior study include ramp-up to participation from prior years, while current study is in its first year
•In the prior study, the AMI program was still in its early planning phase and rollout had to be assumed. In the current study, the AMI rollout is defined by Avista’s active program plan
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 299 of 1057
| 36Applied Energy Group · www.appliedenergygroup.com
Potential in year 2037 by sectorDLC COMPARISON TO PRIOR STUDY
DLC Options Option Current
Study
Previous
Study
Residential DLC Central AC -
DLC Water Heating 16.9
DLC Smart Appliances 3.0
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating 16.0
DLC Electric Vehicle Charging 1.0
Residential Total 37.0
C&I DLC Central AC -
DLC Water Heating 1.7
DLC Smart Appliances 0.4
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating 2.9
Third Party Contracts 23.2 17.8
DLC Controls 4.1
C&I Total 28.1 21.9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 300 of 1057
| 37Applied Energy Group · www.appliedenergygroup.com
Potential in year 2037 by sectorRATES COMPARISON TO PRIOR STUDY
Rates Opt-in Option Current
Study
Previous
Study
Residential Time-of-Use Opt-in 5.8
Time-of-Use Opt-out -
Variable Peak Pricing Rates 16.9
Ancillary Services 0.2
Battery Energy Storage 4.3
Behavioral 3.1
Residential Total 30.3
C&I Time-of-Use Opt-in 1.3 0.7
Time-of-Use Opt-out -
Variable Peak Pricing Rates/ CPP 4.3 3.6
Real Time Pricing 0.6
Ancillary Services 2.3
Thermal Energy Storage -
Battery Energy Storage 0.7
C&I Total 9.2 4.3
Rates Opt-Out Option Current
Study
Previous
Study
Residential Time-of-Use Opt-in -
Time-of-Use Opt-out 19.7
Variable Peak Pricing Rates 5.2
Ancillary Services 0.2
Battery Energy Storage 4.3
Behavioral 3.1
Residential Total 32.5
C&I Time-of-Use Opt-in -
Time-of-Use Opt-out 7.4 3.9
Variable Peak Pricing Rates/ CPP 1.3 10.6
Real Time Pricing 0.2
Ancillary Services 2.3
Thermal Energy Storage -
Battery Energy Storage 0.7
C&I Total 11.9 14.5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 301 of 1057
THANK YOU!
Kurtis Kolnowski, Senior Project [e-mail]
Ken Walter, Senior Energy Analyst
[e-mail]
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 302 of 1057
Sector EE Results
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 303 of 1057
| 40Applied Energy Group · www.appliedenergygroup.com
ENERGY EFFICIENCY POTENTIALPotential Summary –Residential
2021 2022 2025 2030 2040
Reference Baseline (GWh)2,528 2,543 2,607 2,783 3,319
Potential Forecasts (GWh)
Technical Achievable Potential 2,507 2,499 2,476 2,478 2,672
Technical Potential 2,480 2,448 2,367 2,307 2,528
Cumulative Savings (GWh)
Technical Achievable Potential 21 44 131 305 647
Technical Potential 48 96 240 475 791
Energy Savings (% of Baseline)
Technical Achievable Potential 0.8%1.7%5.0%11.0%19.5%
Technical Potential 1.9%3.8%9.2%17.1%23.8%
Incremental Savings (GWh)
Technical Achievable Potential 21 24 33 37 39
Technical Potential 48 48 51 47 34
Washington
2021 2022 2025 2030 2040
Reference Baseline (GWh)1,644 1,658 1,713 1,844 2,226
Potential Forecasts (GWh)
Technical Achievable Potential 1,633 1,635 1,643 1,675 1,845
Technical Potential 1,618 1,605 1,579 1,574 1,758
Cumulative Savings (GWh)
Technical Achievable Potential 11 23 70 168 382
Technical Potential 26 53 134 270 468
Energy Savings (% of Baseline)
Technical Achievable Potential 0.7%1.4%4.1%9.1%17.1%
Technical Potential 1.6%3.2%7.8%14.6%21.0%
Incremental Savings (GWh)
Technical Achievable Potential 11 12 18 22 25
Technical Potential 26 27 29 27 22
Idaho
-
500
1,000
1,500
2,000
2,500
3,000
3,500
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential -
500
1,000
1,500
2,000
2,500
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 304 of 1057
| 41Applied Energy Group · www.appliedenergygroup.com
Top Measures –Residential, Technical Achievable PotentialEE POTENTIAL -CONTINUED
Washington Idaho
Rank 2022 2025 2030
1 11,941
2 8,760
3 2,270
4 -Connected 7,472
5 3,509
6 -Cellular Shades 5,866
7 2,939
8 -Zero 1,342
9 -Low-Flow Showerheads 6,866
10 -in 3,839
54,804
Total Cumulative Savings 44,428 131,104
Rank 2022 2025 2030
1
2
3
4
5 -Connected
6 -Cellular Shades
7 -Zero
8 -Low-Flow Showerheads
9
10 -in
Total of Top 10 Measures 8,798 30,761 95,012 56.5%
Total Cumulative Savings 23,101 69,599 168,308 100.0%
Cooling
8%
Space
Heating
51%
Water
Heating
16%
Interior
Lighting
6%
Exterior
Lighting
2%
Appliances
8%
Electronics
7%Miscellaneous
2%Cooling
8%
Space
Heating
51%
Water
Heating17%
Interior
Lighting7%
Exterior
Lighting
2%
Appliances
8%
Electronics
6%
Miscellaneou
s
1%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 305 of 1057
| 42Applied Energy Group · www.appliedenergygroup.com
ENERGY EFFICIENCY POTENTIALPotential Summary – Commercial
2021 2022 2025 2030 2040
Reference Baseline (GWh)2,162 2,166 2,196 2,292 2,562
Potential Forecasts (GWh)
Technical Achievable Potential 2,140 2,119 2,064 2,014 2,026
Technical Potential 2,114 2,073 1,966 1,862 1,859
Cumulative Savings (GWh)
Technical Achievable Potential 22 47 132 278 536
Technical Potential 47 93 230 430 703
Energy Savings (% of Baseline)
Technical Achievable Potential 1.0%2.2%6.0%12.1%20.9%
Technical Potential 2.2%4.3%10.5%18.7%27.4%
Incremental Savings (GWh)
Technical Achievable Potential 22 25 32 31 22
Technical Potential 47 46 49 40 18
Washington
2021 2022 2025 2030 2040
Reference Baseline (GWh)1,010 1,012 1,029 1,065 1,171
Potential Forecasts (GWh)
Technical Achievable Potential 999 990 965 929 906
Technical Potential 987 968 918 857 826
Cumulative Savings (GWh)
Technical Achievable Potential 11 22 64 136 264
Technical Potential 22 44 110 208 344
Energy Savings (% of Baseline)
Technical Achievable Potential 1.0%2.2%6.2%12.8%22.6%
Technical Potential 2.2%4.4%10.7%19.6%29.4%
Incremental Savings (GWh)
Technical Achievable Potential 11 12 16 15 11
Technical Potential 22 22 23 20 9
Idaho
-
500
1,000
1,500
2,000
2,500
3,000
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential -
200
400
600
800
1,000
1,200
1,400
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 306 of 1057
| 43Applied Energy Group · www.appliedenergygroup.com
Top Measures –Commercial, Technical Achievable PotentialEE POTENTIAL -CONTINUED
Washington Idaho
Rank 2022 2025 2030
1 15,024
2 -Bay Lighting 10,375
3 7,347
4 2,546
5 -Heat Recovery Ventilator 5,394
6 -Evaporative Condenser 5,245
7 2,334
8 -Networked Fixture 3,242
9 -Replace Single-Compressor 3,948
10 -Advanced Controls 1,213
Total of Top 20 Measures 16,084 56,669
131,925
Rank 2022 2025 2030
1
2 -Bay Lighting
3
4 -Heat Recovery Ventilator
5
6
7 -Evaporative Condenser
8 -Networked Fixture
9
10 -Replace Single-Compressor
Total of Top 20 Measures 7,882 27,849 71,428 52.5%
Total Cumulative Savings 22,325 63,909 136,133 100.0%
Cooling
15%Heating
9%
Ventilation
8%
Water
Heating
4%
Interior
Lighting
33%
Exterior
Lighting
14%
Refrigeration
13%
Food
Preparation
2%
Office
Equipment
2%
Miscellaneous
0%
Cooling
16%Heating
8%
Ventilation
8%
Water
Heating
4%
Interior
Lighting
33%
Exterior
Lighting
14%
Refrigeration
13%
Food
Preparation
2%
Office
Equipment2%
Miscellaneous
0%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 307 of 1057
| 44Applied Energy Group · www.appliedenergygroup.com
ENERGY EFFICIENCY POTENTIALPotential Summary –Industrial
2021 2022 2025 2030 2040
Reference Baseline (GWh)553 559 578 612 691
Potential Forecasts (GWh)
Technical Achievable Potential 549 550 552 558 602
Technical Potential 546 544 540 538 578
Cumulative Savings (GWh)
Technical Achievable Potential 4 9 25 54 89
Technical Potential 7 15 38 74 114
Energy Savings (% of Baseline)
Technical Achievable Potential 0.8%1.6%4.4%8.8%12.9%
Technical Potential 1.3%2.6%6.6%12.2%16.4%
Incremental Savings (GWh)
Technical Achievable Potential 4 5 6 6 3
Technical Potential 7 7 8 7 3
Washington
2021 2022 2025 2030 2040
Reference Baseline (GWh)395 395 396 399 407
Potential Forecasts (GWh)
Technical Achievable Potential 392 389 379 364 351
Technical Potential 390 385 371 351 336
Cumulative Savings (GWh)
Technical Achievable Potential 3 6 17 35 56
Technical Potential 5 10 25 48 71
Energy Savings (% of Baseline)
Technical Achievable Potential 0.7%1.6%4.4%8.9%13.7%
Technical Potential 1.2%2.4%6.3%12.0%17.4%
Incremental Savings (GWh)
Technical Achievable Potential 3 3 4 3 2
Technical Potential 5 5 5 4 2
Idaho
-
50
100
150
200
250
300
350
400
450
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential -
100
200
300
400
500
600
700
800
Annual Energy Projections (GWh)
Reference Baseline
Technical Achievable Potential
Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 308 of 1057
| 45Applied Energy Group · www.appliedenergygroup.com
Top Measures –Industrial, Technical Achievable PotentialEE POTENTIAL -CONTINUED
Washington Idaho
Rank 2022 2025 2030
1 -Bay Lighting 2,636
2 3,192
3 -Equipment Upgrade 1,890
4 -Leak Management 1,833
5 714
6 666
7 -Variable Speed Drive 713
8 -Variable Speed Drive 631
9 -Equipment Upgrade 926
10 -Networked Fixture 610
13,811
Total Cumulative Savings 8,883 25,481
Rank 2022 2025 2030
1 -Bay Lighting
2
3 -Equipment Upgrade
4 -Leak Management
5 -Variable Speed Drive
6
7
8 -Variable Speed Drive
9 -Equipment Upgrade
10 -Networked Fixture
Total Cumulative Savings 6,149 17,236 35,326 100.0%
Cooling
4%Heating
10%
Ventilation
3%
Interior
Lighting
24%
Exterior
Lighting
8%
Motors
44%
Process
7%
Miscellaneous
0%
Cooling
4%
Heating
10%Ventilation
3%
Interior
Lighting
22%
Exterior
Lighting
7%
Motors
46%
Process
8%
Miscellaneous
0%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 309 of 1057
Additional Slides from Current Study
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 310 of 1057
| 47Applied Energy Group · www.appliedenergygroup.com
By 2040, by State and Option, TOU Opt-out ScenarioWINTER PEAK MW REDUCTIONS
Winter Potential in 2040 ID WA Grand
Total
DLC
DLC Central AC 0.00 0.00 0.00
DLC Water Heating 6.88 12.38 19.27
DLC Smart Thermostats -Cooling 1.24 2.21 3.45
DLC Smart Thermostats -Heating 0.00 0.00 0.00
DLC Smart Appliances 7.14 12.60 19.74
DLC Electric Vehicle Charging 0.39 0.74 1.14
Third Party Contracts 8.47 14.78 23.25
Rates
Time-of-Use Opt-in
Time-of-Use Opt-out 9.47 17.95 27.42
Variable Peak Pricing Rates 2.30 4.30 6.59
Real Time Pricing 0.06 0.12 0.18
Ancillary Services 0.93 1.55 2.48
Thermal Energy Storage 0.00 0.00 0.00
Battery Energy Storage 1.87 3.34 5.21
Behavioral 1.07 2.08 3.15
Grand Total 39.83 72.05 111.88
0 5 10 15 20 25 30
DLC Central AC
DLC Water Heating
DLC Smart Appliances
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating
DLC Electric Vehicle Charging
Third Party Contracts
Time-of-Use Opt-in
Time-of-Use Opt-out
Variable Peak Pricing Rates
Real Time Pricing
Ancillary Services
Thermal Energy Storage
Battery Energy Storage
Behavioral
Achievable Potential (MW)
Winter DR Potential in 2040
ID WA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 311 of 1057
| 48Applied Energy Group · www.appliedenergygroup.com
SUMMER POTENTIAL IN 2040 BY STATE
(TOU OPT-OUT)
Summer Potential in 2040 ID WA Grand Total
Ancillary Services 0.8 1.4 2.2
DLC Central AC 2.9 4.9
12.4
2.2
4.2
0.1
2.1 3.1
0.5
3.3
-Cooling 5.1
-Heating
13.2
0.7 1.1
-of-Use Opt-in
-of-Use Opt-out 17.3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 312 of 1057
Stand-Alone Results by Program
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 313 of 1057
| 50Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –WINTER DLC
Sector Option 2021 2022 2030 2040
Residential DLC Central AC ----
DLC Water Heating 1.4 4.3 15.6 17.5
DLC Smart Appliances 0.3 0.8 2.8 3.1
-Cooling
-Heating
-Cooling
-Heating
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 314 of 1057
| 51Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –SUMMER DLC
Sector Option 2021 2022 2030 2040
Residential DLC Central AC 0.5 1.4 5.4 6.2
DLC Water Heating 1.4 4.3 15.6 17.5
DLC Smart Appliances 0.3 0.8 2.8 3.1
DLC Smart Thermostats -Cooling
-Heating
-Cooling
-Heating
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 315 of 1057
| 52Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –WINTER RATES AND
OTHER OPTIONS
Sector Option 2021 2022 2030 2040
Residential Time-of-Use Opt-in
-of-Use Opt-out 22.1
0.1
-of-Use Opt-in
-of-Use Opt-out
1.1
-
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 316 of 1057
| 53Applied Energy Group · www.appliedenergygroup.com
MW BY OPTION –SUMMER RATES
AND OTHER OPTIONS
Sector Option 2021 2022 2030 2040
Residential Time-of-Use Opt-in
-of-Use Opt-out
-of-Use Opt-in
-of-Use Opt-out
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 317 of 1057
Smart Grid
Demonstration Project
2009 –2015 Pullman WA
www.smartgrid.gov/files/OE0000190_Battelle_FinalRep_2015_06.pdf
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 318 of 1057
Battelle NWBonneville Power
Administration
3 Tier
Areva
IBM
Netezza
Quality
Logic
Utility Partners
Avista
Benton PUD
City of Ellensburg
Flathead Electric
Idaho Falls Power
Lower Valley Energy
Milton-Freewater
Northwestern Energy
Peninsula Light
PGE
Seattle City Light
NETL
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 319 of 1057
Transactive System
Figure courtesy of PNNL study Transactive System, December 2017
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 320 of 1057
Avista Demand Response
Smart thermostats
•Residential & Small Commercial
–Air-Conditioning
–& some electric heat loads
•Avg. 57 participants (up to 75)
•637 DR Events (Transactive & AGS)
–Duration 5 minutes -6 hours
Washington State University
Tier 1 HVAC (39 points)12 DR events
Tier 2 Chillers (9 points)5 DR events
Tier 3-5 Generators 5 DR events
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 321 of 1057
Smart Meter Usage Web Portal
Bill-to-Date & Usage Charts
Customer Engagement
and Energy Efficiency Usage notifications &
alerts between bills
Daily: Comparison
Weekly: Bill-to-date
Monthly: Budget threshold
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 322 of 1057
New Customer Programs
Smart Thermostat Rebates
Washington Smart Meter Roll-Out
New AMI Web-Portal Features
<demo AMI web-portal>
Notifications & Alerts
Add to Mobile App Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 323 of 1057
QUESTIONS…
COMMENTS…
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 324 of 1057
Resource Adequacy in the
Pacific Northwest
Serving Load Reliably under a Changing
Resource Mix
February 2019
Resource Adequacy in the
Pacific Northwest
Serving Load Reliably under a Changing
Resource Mix
Arne Olson, Sr. Partner
Zach Ming, Managing ConsultantExhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 325 of 1057
Outline
Study Background & Methodology
Results
•2018
•2030
•2050
•Capacity contribution of wind, solar, storage and demand response
Key Findings
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 326 of 1057
STUDY BACKGROUND
& METHODOLOGY
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 327 of 1057
4
About This Study
The Pacific Northwest is expected to undergo
significant changes to its generation resource mix
over the next 30 years due to changing economics
and more stringent policy goals
•Increased penetration of wind and solar generation
•Retirements of coal generation
•Questions about the role of new natural gas generation
This raises questions about the region’s ability to serve load
reliably as firm generation is replaced with variable resources
This study was sponsored by 13 Pacific Northwest utilities to
examine Resource Adequacy under a changing resource mix
•How to maintain Resource Adequacy in the 2020-2030 time
frame under growing loads and increasing coal retirements
•How to maintain Resource Adequacy in the 2040-2050 time
frame under stringent carbon abatement goals
Historical and Projected GHG Emissions for OR and WA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 328 of 1057
5
Study Sponsors
This study was sponsored by Puget Sound Energy, Avista,
NorthWestern Energy and the Public Generating Pool (PGP)
•PGP is a trade association representing 10 consumer-owned utilities in
Oregon and Washington.
E3 thanks the staff of the Northwest Power and Conservation Council for providing data and technical reviewExhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 329 of 1057
6
Three Reliability Challenges on a
Deeply-Decarbonized Grid
High Load
Low Wind & Solar
Low Hydro Year
1
2
3
Loss of load
event of
nearly 48 hrs Loss of load
magnitude of
over 30 GW
The most challenging conditions in a deeply-decarbonized Pacific Northwest grid occur
when a multi-day cold snap coincides with low wind, solar and hydro production
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 330 of 1057
7
Long-run Reliability and Resource
Adequacy
This study focuses on long-run (planning) reliability, a.k.a. Resource
Adequacy (RA)
•A system is “Resource Adequate” if it has sufficient capacity to serve load across
a broad range of weather conditions, subject to a long-run standard for
frequency of reliability events, for example 1-day-in-10 yrs.
There is no mandatory or voluntary national standard for RA
•Each Balancing Authority establishes its own standard subject to oversight by
state commissions or locally-elected boards
•North American Electric Reliability Council (NERC) and Western Electric
Coordinating Council (WECC) publish information about Resource Adequacy but
have no formal governing role
Study uses a 1-in-10 standard of no more than 24 hours of lost load in 10
years, or no more than 2.4 hours/year
•This is the most common standard used across the industry Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 331 of 1057
8
Study Region –The Greater NW
The study region consists of the
U.S. portion of the Northwest
Power Pool (excluding Nevada)
It is assumed that any resource in
any area can serve any need
throughout the Greater NW region
•Study assumes no transmission
constraints or transactional friction
•Study assumes full benefits from
regional load and resource
diversity
•The system as modeled is more
efficient and seamless than the
actual Greater NW system
Balancing Authority Areas include: Avista, Bonneville
Power Administration, Chelan County PUD, Douglas
County PUD, Grant County PUD, Idaho Power,
NorthWestern Energy, PacifiCorp (East & West),
Portland General Electric, Puget Sound Energy, Seattle
City Light, Tacoma Power, Western Area Power
Administration Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 332 of 1057
9
New wind and solar resources are added
across a geographically diverse footprint
The study considers additions nearly 100 GW of wind
and 50 GW of solar across the six-state region
The portfolios studied are significantly more diverse
than the renewable resources currently operating in
the region
•Each dot in the map represents a location where
wind and solar is added in the study
•NW wind is more diverse than existing Columbia Gorge
wind
New renewable portfolios are within the bounds of
current technical potential estimates, but are nearly an
order of magnitude higher than other studies have
examined
The cost of new transmission is assumed for delivery of
remote wind and solar generation but siting and
construction is not studied in detail
State Wind
WA 18
OR 27
CA 34
ID 18
MT 944
WY 552
UT 13
Total 1588https://www.nrel.gov/docs/fy12osti/51946.pdf
NREL Technical Potential (GW)
NW Wind
MT Wind
WY Wind
Solar
Additional
transmission
cost ($50/kW-yr)
associated with
MT and WY wind
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 333 of 1057
10
Additional metric definitions used for
scenario development
GHG Reduction %is the reduction below 1990 emission levels for the
study region
•The study region emitted 60 million metric electricity sector emissions in 1990
CPS %is the total quantity of GHG-free generation divided by retail
electricity sales
•“Clean Portfolio Standard” includes renewable energy plus hydro and nuclear
•Common policy target metric, including California’s SB 100
GHG-Free Generation %is the total quantity of GHG-free generation,
minus exported GHG-free generation, divided by total wholesale load
•Assumed export capability up to 6,000 MW
Renewable Curtailment %is the total quantity of wind/solar generation
that is not delivered or exported divided by total wind/solar generationExhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 334 of 1057
11
The study considers Resource Adequacy needs under multiple scenarios
representing alternative resource mixes
2050 Scenarios Carbon Reduction
% Below 19901
GHG-Free
Generation %2 CPS %3
Carbon Emissions
(MMT)
Reference Case 16%60%63%50
60% GHG Reduction 60%80%86%25
80% GHG Reduction 80%90%100%12
90% GHG Reduction 90%95%108%6
98% GHG Reduction 98%99%117%1
100% GHG Reduction 100%100%123%0
2018-2030 Scenarios Carbon Reduction
% Below 19901
GHG-Free
Generation %2 CPS %3
Carbon Emissions
(MMT)
2018 Case4 -6%71%75%63
2030 Reference Case4 -12%61%65%67
2030 Coal Retirement 30%61%65%42
1Greater NW Region 1990 electricity sector emissions = 60 MMT/yr.
2GHG-Free Generation % = renewable + hydro + nuclear generation, minus exports, divided by total wholesale load
3CPS % = renewable + hydro + nuclear generation divided by retail electricity sales
42018 and 2030 cases assumes coal capacity factor of 60%Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 335 of 1057
12
Individual utility impacts will
differ from the regional impacts
Cost impacts in this study are presented from a societal perspective and
represent an aggregation of all costs and benefits within the Greater NW
region
•Societal costs include all investment (i.e. “steel-in-the-ground”) and operational
costs (i.e. fuel and O&M) that are incurred in the region
Cost of decarbonization may be higher or lower for individual utilities as
compared to the region as a whole
•Utilities with a relatively higher composition of fossil resources today are likely
to bear a higher cost than utilities with a higher composition of fossil-free
resources
Resource Adequacy needs will be different for each utility
•Individual systems will need a higher reserve margin than the Greater NW
region due to smaller size and less diversity
•Capacity contribution of renewables will be different for individual utilities due
to differences in the timing of peak loads and renewable generation productionExhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 336 of 1057
2030 RESULTS
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 337 of 1057
14
2030 Portfolios
5 GW net new capacity
by 2030 is needed for
reliability (450 MW/yr)
With planned coal
retirements of 3 GW, 8
GW of new capacity by
2030 is needed
(730 MW/yr)
If all coal is retired,
then 16 GW new
capacity is needed
(1450 MW/yr)
GHG Free Generation (%)61%61%
Carbon (MMT CO2)67 42
% GHG Reduction from 1990 Level -12%*31%
*Assumes 60% coal capacity factor
2018 2030
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 338 of 1057
15
The Northwest system will need 8 GW of
new effective capacity by 2030
2030 with No
New Capacity
2030 with 8 GW of
New Capacity
Annual LOLP (%)48%2.8%
LOLE (hrs/yr)106 2.4
EUE (MWh/yr)178,889 1,191
EUE norm (EUE/load)0.07%0.0004%
The 2030 system does not meet 1-in-10 reliability standard (2.4 hrs./yr.)
The 2030 system does not meet standard for Annual LOLP (5%)
Load growth and planned coal retirements lead to the need for 8 GW of new
effective capacity by 2030
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 339 of 1057
2050 RESULTS
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 340 of 1057
171CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Scenario Summary
Greater NW System in 2050
2050 Reference Scenario
Total cost of new resource
additions is $4 billion per year
(~$30 billion investment)
2018 2050
Additions Retirements
2 GW Wind
4 GW Solar
20 GW Gas
11 GW Coal
9 GW
net
increase
in firm
capacity
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 341 of 1057
181CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Scenario Summary
Greater NW System in 2050
4-hr
4-hr 4-hr
4-hr
6-hr
2018 2050
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 342 of 1057
19
Illustrating the Need for
Firm Capacity –January
10 Day Cold Stretch In January
Despite 60 GW of installed renewable capacity in the 80% reduction
scenario, gas and hydro are needed during low generation periods
80% Reduction Portfolio Including Gas
Gas & hydro ramp up during periods of high
load and low renewable production
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 343 of 1057
20
Illustrating the Need for
Firm Capacity –January
10 Day Cold Stretch In January
80% Reduction Case Without Gas
Without gas, the system is energy deficient during prolonged
stretches of low wind and solar production
Loss of Load
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 344 of 1057
21
Scenario Summary
2050 Emissions Reductions
4-hr
4-hr 4-hr
4-hr
6-hr20182050
Carbon (MMT CO2)50 25 12 6 1 -
CPS (%)1 63%86%100%108%117%123%
GHG Free Generation (%)2 60%80%90%95%99%100%
% GHG Reduction from 1990 level 16%60%80%90%98%100%
1CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 345 of 1057
22
Scenario Summary
2050 Resource Use
4-hr
4-hr 4-hr
4-hr
6-hr20182050
Renewable Capacity (GW)13 34 49 59 83 143
Annual Renewable Curtailment (%)Low Low 4%10%21%47%
Gas Capacity (GW)32 26 24 20 14 0
Gas Capacity Factor (%)46%27%16%9%3%0%
1CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 346 of 1057
23
2050 Annual Energy Balance
Load 309 TWh/yr
46%
Gas CF
27%
Gas CF
16%
Gas CF
9%
Gas CF
3%
Gas CF
0%
Gas CF
Gas capacity factor declines significantly at
higher levels of decarbonization
Significant curtailed renewable energy at
deep levels of carbon reductions
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 347 of 1057
24
Firm capacity is still needed for reliability under deep decarbonization
despite much lower utilization
Natural gas energy production declines substantially as the GHG
increases
Natural gas capacity is part of the least-cost mix of resources to
reduce carbon emissions to 1 million tons by 2050
All scenarios except 100% GHG reductions select more gas capacity
than exists on the system today (12 GW)
14 GW of gas
capacity needed
even under 98%
GHG Reduction
scenario
Despite retention of gas capacity
for reliability, capacity factor
declines precipitously as more
wind, solar, and storage are added
for decarbonization
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 348 of 1057
251CPS+ % = renewable/hydro/nuclear generation divided by retail electricity sales
2GHG-Free Generation % = renewable/hydro/nuclear generation, minus exports, divided by total wholesale load
Scenario Summary
2050 Costs
4-hr
4-hr 4-hr
4-hr
6-hr20182050
Marginal Carbon Reduction Cost
($/Metric Ton)
Base $0 -$80 $90 -
$190
$110 -
$230
$310 -
$700
$11,000 –
$16,000
Annual Cost Delta ($B)Base $0 -$2 $1 -$4 $2 -$5 $3 -$9 $16 -$28
Additional Cost ($/MWh)Base $0 -$7 $3 -$14 $5 -$18 $10 -$28 $52 -$89
Removing final 1% of carbon requires
additional $100b to $170b of investment
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 349 of 1057
26
Marginal Cost of GHG Reduction
80% GHG Free 90% GHG Free 95% GHG Free 99% GHG Free
86% CPS 100% CPS 108% CPS 117% CPS
Marginal cost of CO2 reductions at
90% GHG Reductions or greater
exceed most estimates of the
societal cost of carbon which
generally range from $50/ton to
$250/ton1, although some academic
estimates range up to $800/ton1
1 https://19january2017snapshot.epa.gov/climatechange/social-cost-carbon_.html;
https://www.nature.com/articles/s41558-018-0282-y
High Cost Range
Low Cost Range
$80
$190
$230
$700
$310
$110$90
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 350 of 1057
27
Marginal Cost of GHG Reduction
80% GHG Free 90% GHG Free 95% GHG Free 99% GHG Free 100% GHG Free
86% CPS 100% CPS 108% CPS 117% CPS 123% CPS
Marginal cost of absolute
100% GHG reductions vastly
exceeds societal cost of
carbon, confirming
conclusion on impracticality
Previous slide
High Cost
Range
Low Cost
Range
$80
$0
$190 $230 $700
$310$110$90
$16,000
$11,000
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 351 of 1057
28
100% Reduction
Portfolio Alternatives in 2050
6-hr
926-hr
4-hr
2018 2050
Clean baseload or biogas or
ultra-long duration storage
resource could displace
significant wind and solar
4-hr
Base Case
100% Zero
Carbon
Uncertain Technical/Cost/Political Feasibility
Clean baseload
would require
SMR or other
undeveloped
technology
Ultra-long
duration
storage
technology is
not
commercial
Biogas
potential is
uncertain
Carbon (MMT CO2)50 0 0 0 0
Annual Cost Delta ($B)Base $16-$28 $14-$21 $550-$990 $4 -$9
Additional Cost ($/MWh)Base $52-$89 $46-$69 $1,800-$3,200 $14 -$30 Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 352 of 1057
29
Renewable Land Use
2018 Installed Renewables
Technology Nameplate GW
Solar 1.6
NW Wind 5.3
MT Wind 0.6
WY Wind 1.2
Portland land area is 85k acres
Seattle land area is 56k acres
Oregon land area is 61,704k acres
Each point on the map indicates 200 MW.
Sites not to scale or indicative of site location.
Land use today ranges from
1.6 to 7.5x
the area of Portland and Seattle combined
Solar
Total
Land
Use
(thousand acres)
Wind -
Direct
Land
Use
(thousand acres)
Wind –
Total Land
Use
(thousand acres)
Today 12 19 223 –1,052
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 353 of 1057
30
Renewable Land Use
80% Reduction in 2050
Technology Nameplate GW
Solar 11
NW Wind 36
MT Wind 0
WY Wind 2
Solar
Total
Land Use
(thousand
acres)
Wind -
Direct
Land Use
(thousand
acres)
Wind -
Total
Land Use
(thousand
acres)
80%
Red
84 94 1,135 –
5,337
Portland land area is 85k acres
Seattle land area is 56k acres
Oregon land area is 61,704k acres
Each point on the map indicates 200 MW.
Sites not to scale or indicative of site location.
Land use in 80% Reduction case ranges from
8 to 37x
the area of Portland and Seattle combined
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 354 of 1057
31
Renewable Land Use
100% Reduction in 2050
Technology Nameplate GW
Solar 46
NW Wind 47
MT Wind 18
WY Wind 33
Portland land area is 85k acres
Seattle land area is 56k acres
Oregon land area is 61,704k acres
Solar
Total
Land Use
(thousand
acres)
Wind -
Direct
Land Use
(thousand
acres)
Wind -
Total
Land Use
(thousand
acres)
80%
Clean
84 94 1,135 –
5,337
100%
Red
361 241 2,913 –
13,701
Each point on the map indicates 200 MW.
Sites not to scale or indicative of site location.
Land use in 100% Reduction case ranges from
20 to 100x
the area of Portland and Seattle combined
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 355 of 1057
32
Wind ELCC varies widely by
location
Diverse
New MT/WY
New NW
Existing NW
Existing NW wind (mostly in Columbia Gorge)
provides very low capacity value due to strong
negative correlation with peak loads
New NW wind might have higher capacity value if
diverse resources can be developed
New MT/WY wind provides very high capacity value
due to strong winter winds that are positively
correlated to NW peak loads
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 356 of 1057
33
Effective capacity from wind, solar, storage, and demand response is limited
due to saturation effects
Diverse Wind (NW, MT, WY)Solar
6-Hr Storage Demand Response
ELCC = Effective Load Carrying Capability = firm
contribution to system peak load
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 357 of 1057
34
Value of Storage Duration
6-Hr Storage 12-Hr Storage
Storage Only
Storage + Diversity
Allocation
Storage Only
Storage + Diversity
Allocation
Increasing the duration of storage provides additional
ELCC capacity value, but there are still strong
diminishing returns even for storage up to a duration
of 12-hours
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 358 of 1057
KEY FINDINGS
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 359 of 1057
36
Key Findings (1 of 2)
1.It is possible to maintain Resource Adequacy for a deeply decarbonized Northwest
electricity grid, as long as sufficient firm capacity is available during periods of low
wind, solar and hydro production
o Natural gas generation is the most economic source of firm capacity, and adding new gas
capacity is not inconsistent with deep reductions in carbon emissions
o Wind, solar, demand response and short-duration energy storage can contribute but have
important limitations in their ability to meet Northwest Resource Adequacy needs
o Other potential low-carbon firm capacity solutions include (1) new nuclear generation,
(2) gas or coal generation with carbon capture and sequestration, (3) ultra-long duration
electricity storage, and (4) replacing conventional natural gas with carbon-neutral gas
2.It would be extremely costly and impractical to replace all carbon-emitting firm
generation capacity with solar, wind and storage, due to the very large quantities of
these resources that would be required
3.The Northwest is anticipated to need new capacity in the near-term in order to
maintain an acceptable level of Resource Adequacy after planned coal retirements
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 360 of 1057
37
Key Findings (2 of 2)
4.Current planning practices risk underinvestment in new capacity required to
ensure Resource Adequacy at acceptable levels
o Reliance on “market purchases” or “front office transactions” reduces the cost of
meeting Resource Adequacy needs on a regional basis by taking advantage of load and
resource diversity among utilities in the region
o However, because the region lacks a formal mechanism for counting physical firm
capacity, there is a risk that reliance on market transactions may result in double-
counting of available surplus generation capacity
o Capacity resources are not firm without a firm fuel supply; investment in fuel delivery
infrastructure may be required to ensure Resource Adequacy even under a deep
decarbonization trajectory
o The region might benefit from and should investigate a formal mechanism for sharing of
planning reserves on a regional basis, which may help ensure sufficient physical firm
capacity and reduce the quantity of capacity required to maintain Resource Adequacy
The results/findings in this analysis represent the Greater NW region
in aggregate, but results may differ for individual utilities Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 361 of 1057
Thank You!
Energy and Environmental Economics, Inc. (E3)
101 Montgomery Street, Suite 1600
San Francisco, CA 94104
Tel [phone]
Web http://www.ethree.com
Arne Olson, Senior Partner ([e-mail])
Zach Ming, Managing Consultant ([e-mail])
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 362 of 1057
39
This study utilizes E3’s Renewable
Energy Capacity Planning (RECAP) Model
Resource adequacy is a critical concern under
high renewable and decarbonized systems
•Renewable energy availability depends on the
weather
•Storage and Demand Response availability
depends on many factors
RECAP evaluates adequacy through time-
sequential simulations over thousands of
years of plausible load, renewable, hydro,
and stochastic forced outage conditions
•Captures thermal resource and transmission
forced outages
•Captures variable availability of renewables &
correlations to load
•Tracks hydro and storage state of charge
72°
Storage Hydro DR
RECAP calculates reliability
metrics for high renewable
systems:
•LOLP:Loss of Load Probability
•LOLE:Loss of Load Expectation
•EUE:Expected Unserved Energy
•ELCC:Effective Load-Carrying
Capability for hydro, wind, solar,
storage and DR
•PRM:Planning Reserve Margin
needed to meet specified LOLE
Information about E3’s RECAP model can be found here:
https://www.ethree.com/tools/recap-renewable-energy-capacity-planning-model/
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 363 of 1057
40
RECAP calculates a number of metrics
that are useful for resource planning
Annual Loss of Load Probability (aLOLP) (%):is the probability of a
shortfall (load plus reserves exceed generation) in a given year
Annual Loss of Load Expectation (LOLE) (hrs/yr):is total number of
hours in a year wherein load plus reserves exceeds generation
Annual Expected Unserved Energy (EUE) (MWh/yr):is the expected
unserved load plus reserves in MWh per year
Effective Load Carrying Capability (ELCC) (%):is the additional load met
by an incremental generator while maintaining the same level of system
reliability (used for dispatch-limited resources such as wind, solar,
storage and demand response)
Planning Reserve Margin (PRM) (%):is the resource margin above 1-in-
2-year peak load, in %, that is required in order to maintain acceptable
resource adequacy
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 364 of 1057
41
“ELCC” is used to determine effective capacity contribution from wind, solar,
storage and demand response
Effective load carrying capability (ELCC) is the quantity of ‘perfect
capacity’ that could be replaced or avoided with dispatch-limited
resources such as wind, solar, hydro, storage or demand response while
providing equivalent system reliability
The following slides present ELCC values calculated using the
2050 80% GHG Reduction Scenario as the baseline conditions
Original system
LOLE
LOLE improves
after wind/solar/
storage/DR
Reduction in perfect
capacity to return to
original system LOLE
= ELCC
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 365 of 1057
42
2030
Load (GW)
Peak Load (Pre-EE)50.0
Peak Load (Post-EE)47.0
PRM 12%
PRM 5.0
Total Load Requirement 52.0
Resources / Effective Capacity (GW)
Coal 8.0
Gas 20.0
Bio/Geo 0.6
Imports 2.0
Nuclear 1.0
DR 1.0
Nameplate
Capacity (GW)ELCC (%)Capacity
Factor (%)
Hydro 19.0 35.0 56%44%
Wind 0.6 7.1 9%26%
Solar 0.2 1.6 14%27%
Storage 0.0
Total Supply 52.0
2030 Load and Resource Balance
8 GW new
gas capacity
needed by
2030
Wind and solar contribute
little effective capacity
with ELCC* of 9% and 14%
*ELCC = Effective Load Carrying Capability =
firm contribution to system peak load
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 366 of 1057
43
2050
80%
Reduction
90%
Reduction
100%
Reduction
Load (GW)
Peak (Pre-EE)65 65 65
Peak (Post-EE)54 54 54
PRM (%)9%9%7%
PRM 5 5 4
Total Load
Requirement 59 59 57
Resources / Effective Capacity (GW)
Coal 0 0 0
Gas 24 20 0
Bio/Geo 0.6 0.6 0.6
Imports 2 2 0
Nuclear 1 1 1 Nameplate Capacity (GW)ELCC (%)Capacity Factor (%)
DR 1 1 1 80% Red.90% Red.100% Red.80% Red.90% Red.100% Red.80% Red.90% Red.100% Red.
Hydro 20 20 20 35 35 35 58%58%57%44%44%44%
Wind 7 11 21 38 48 96 19%22%22%35%36%37%
Solar 2.0 2.2 7.5 11 11 46 19%21%16%27%27%27%
Storage 1.6 1.8 5.8 2.2 4.4 29 71%41%20%N/A N/A N/A
Total Supply 59 59 57
2050 Load and Resource Balance
Wind ELCC* values are higher
than today due to significant
contribution from MT/WY wind
*ELCC = Effective Load Carrying Capability =
firm contribution to system peak load Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 367 of 1057
Attendees: TAC 3, Tuesday, April 16, 2019 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; James Gall, Avista; Leona Doege, Avista; Amber Gifford, Avista; Kurtis Kolnowski, AEG; Ken Walter, AEG; Brian Parker, 350.org; John Barber, Rockwood Retirement Community; Doug Howell, Sierra Club; Barry Kathrens, 350.org; Ryan Finesilver, Avista; Clint Kalich, Avista; Dave Van Hersett, Avista Customer; Matt Nykiel, Idaho Conservation League; Amy Wheeless, NW Energy Coalition; Michael
Eldred, Idaho Public Utilities Commission; Rachelle Farnsworth, Idaho Public Utilities Commission; Aimee Higby, Washington Utilities and Transportation Commission; Jennifer Snyder, Washington Utilities and Transportation Commission; Xin Shane, Avista; Terrence Browne, Avista; Scott Wilson, Avista; Damon Fisher, Avista; Tracy Rolstad, Avista; John Gross, Avista; Chris Zentz, National Grid; Eric Lee, 4Sight
Energy; and Garrett Brown, Avista.
Phone Participants:
Sarah Laycock, Washington State Attorney General’s Office plus two others; Mike
Starrett, Power Council; Nancy Esteb, NW Energy Coalition; and David Howarth,
National Grid Ventures.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista/Presenter responses are in italics,
and significant points raised by presenters that are not shown on the slides are also
included.

Introductions and TAC 2 Recap, John Lyons
Doug Howell: Request for studies, what has changed? Some studies, such as those
shutting down Colstrip at later dates, may no longer be necessary with the legislative
changes.
Matt Nykiel: Update on the RFP for wind and solar? Already included using information
from the recent RFP.
Dave Van Hersett: What is the length of the PPA for wind? 20 years with a confidential
price that we cannot make public. Lind Solar is also a 20-year PPA. The cost
assumption for new wind is in the low $30/MWh range and would roughly be the energy
portion of a customer bill.
Kathlyn Kinney: Is it cheaper than coal? Hard to compare old/new coal and the
attributes. Old coal is an existing sunk costs, lower costs to run, so can be cheaper for
an existing coal plant. Also, new coal plants cannot be built under Washington law.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 368 of 1057
Regional Legislative Update, John Lyons
Dave Van Hersett: Cow power? Cow manure in a digester that counts as biomass
power.
1444 requires new electric water storage under the water heater provision.
Doug Howell: Coal-fired provision. 11 million tons of emissions makes me concerned
over resources being put into Colstrip. Provisions in the ownership contract not have to
pay for, and prolonging the life of the resource.
Dave Van Hersett: I prefer reliable resources that don’t raise my rates. Last 40 years
effect of forest fires. AVA vs. PSE.
Doug Howell: Cleanup costs Units 3 and 4 expected to be $780 million. Montana AG
superfund site which are often 2, 5 or 8 times more expensive to remediate than
expected.
Linda Faulkner Gervais: No matter where or how we will continue to discuss the capital
costs at Colstrip with the regulators.
Jennifer Snyder: Have you considered modeling the IRP out to 2045? Yes, we actually
look out 25 to 30 years, but have only shown 20 years in the IRP.
John Barber: The general thrust of Montana is opposite that of Washington. Yes.
SB 5116 also has a 2% cost cap for meeting the renewable portion of the law over 4-
year blocks to help with hydro variability.
Matt Nykiel: Is there an update on the coal contracts? Yes, the new mine owners that
took over after Westmoreland are honoring the contract through the end of 2019 and we
are working on a new contract.
Dave Van Hersett: What are in the [SB] 5116 rulemakings? Things such as the 2.5
discount rate for social cost of carbon.
Matt Nykiel: How prices might increase with coal contract? Are you using scenarios on
price for coal. We expect a new coal contract by the end of the year.

IRP Transmission Planning Studies, Tracy Rolstad
Doug Howell: [SB] 5116 transmission reliability? Experience of Federal rules are
relatively tight and give us the mechanisms to study it. State laws are a mix of resiliency
and reliability. They are probably not going to be more demanding than that table on
slide 9.
Dave Van Hersett: What is a non-wires solution? Perhaps a battery to discharge. Install
and operate series capacitors or reactors to increase power flow on lines or force power
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 369 of 1057
flow onto other lines to maximize utilization of existing transmission capacity. We want
to maximize existing infrastructure with these non-wires solutions.
Dave Van Hersett: What is the biggest battery? 100 MW in Australia, but it is still in
development.
James Gall: Battery duration is the challenge. Currently 4 hours, maybe up to 6 hours,
and we need 8 to 18 hours from a battery.
Location specific is the issue. Placement and duration.
Clint Kalich: Coordination – transformer sits there and performs as needed. Batteries –
is this a solution to many of our problems? $200 million versus a $2.5 million solution.
Novel idea, will it find a place where it performs well. The policy is up against the
technology. Give us enough money and we will make anything work.
Clint Kalich: Othello/Lind? About 800 MW in the queue in this area. There was about
2,000 MW in our RFP and a bunch if it was there.
Kathlyn Kinney: Looks to me like it makes smaller projects easier to build. In the past,
we have posted on Oasis here are the places where you can plug in certain amounts of
generation relatively cheap. Speculative developers can look at this and decide where
to go. Small numbers or really powerful parts of our system.
Jim Le Tellier: How does this work? We have to respect the queue and layer it on to
engage in queue management. On ramps/off ramps for a cluster study or look at it all
together instead of first come first served. Take or pay. Can sign a contract for
transmission.
Dave Van Hersett: What is RAS? Remedial action scheme. Only owner or developer of
generation agrees to be tripped for a line loss. Done all over the northwest. It saves the
need for a new transmission line. Not really at this time in the IRP process, but rotating
machines have bigger impacts of those in play in northwest for 40 years (non-wires
solution).
Doug Howell: Do you have to use it [RAS] often? It happens, but not often. BPA has
saved billions of dollars doing this.
Dave Van Hersett: Not your distribution, its transmission. How much of an addition to
transmission over the next 20 years? Good question. It depends on where it goes,
shaping intermittency. California’s load literally goes away during the day, but gets busy
at night. BC Hydro sells energy to California to cover the ramp up which could be a
challenge in the future. No empirical data yet, but very good modeling. Predictability is
quite a bit less now, it’s not your grandfather’s utility.
Jim Le Tellier: Fairly represent marginal cost for developers who pay those costs for us.
If another utility gets it, then they pay all or some of the network upgrades. The
lumpiness of these upgrades affords opportunities for others.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 370 of 1057
James Gall: Small portion of costs relative to the grand scheme of things. Upfront costs
amortized over 50 years.
Dave Van Hersett: How does wind/solar affect the timing and different directions of our
transmission capability. It is behaving differently, but still operating. California is going to
become a net exporter and we will need to manage hydro differently.

Distribution Planning within the IRP, Damon Fisher
John Barber (Slide 5, August 10th, 106 degrees): Did load end higher than it began?
The day was hotter than the last and lines cut off by software.
Damon Fisher (Slide 8): Does the electric car load take away the ability to shift other
load at night?
John Barber: You said two Waikiki feeders serve Whitworth area. Rockwood is up there
too, when do batteries come in? That is in the middle of the most vulnerable area.
Jennifer Snyder: Do we look at one or more coordinated interventions targeted for
efficiency, whole package or by measure? Intend to look at a package. Feeder-by-
feeder, considering the costs of all solutions.
Dave Van Hersett: But the transmission guy said that batteries won’t work. Scale and
cost of problems being solved with batteries are different between distribution and
transmission.
Kathlyn Kinney: Curious if storage folks bear cost like Costco. We have an obligation to
serve where we credit them some of the cost of installation. Can’t really charge benefits
to the whole system.
Garrett Brown: Schedule 51 line extension tariffs for cost sharing that identifies all of the
components.
Slide #9: modest photovoltaic (rooftop solar) assumes 300 installs of 5 kW on feeder,
1.5 MW of solar per feeder.
Doug Howell (Slide 10): There doesn’t look to be any advantage to battery cost, is that
the full story? No, do we install a substation for $5 million or a $25 million battery with all
of the other benefits it provides? To who and when is the stated value happening? This
slide is what it looks like to the distribution system only.

Conservation Potential Assessment, AEG
James Gall: We have a need based on Grant’s load forecast. We want all resources to
compete at the same time so they are treated equally. Old way was back and forth
where errors could be made and could miss things mathematically.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 371 of 1057
Jennifer Snyder: Every measure is individual against demand response and generation,
peak and energy level.
Clint Kalich: Customized avoided cost. May incentivize them based on cost, but that
doesn’t account for characteristics rather than lumping them together. Lowering risk
instead of iterating.
Barry Kathrens: Do we consider building codes with a solar requirement? No, we stick
to what is on the books. Why not? Would need to talk to the legislature, AEG could
supply some estimates. Energy efficiency is not as simple since there are real impacts
to the distribution system. Could try a scenario.
Doug Howell: What are TRC and UCT? Total Resource Cost is used in Washington and
Utility Cost Test is used in Idaho. UCT only looks at the portion of cost the utility bears,
so we don’t include customer benefits like saving water. More potential passes [for
programs] because of lower upfront costs.
Jennifer Snyder (Slide 8): everyone technical 100% (ramp rates with RTF).
Doug Howell: Look at doing a deep retrofit. That is the finance mechanism, so if cost
effective, we could do it. We are present valuing all of the benefits and costs. Bundling
all of the benefits.
Clint Kalich: Maybe we need to meet on this. Public vs. IOU, average low bundle, but a
lot of those programs wouldn’t fit.
PSE had a solicitation demonstration project [of a deep retrofit].
Jennifer Snyder: Achievement needs to stay cost effective at the portfolio level.
Doug Howell: Washington State study says we need deep efficiency and we are not
achieving that by missing the dynamic of how a building operates. This could be
encouraged with Avista financing – Housing Finance Corp.
Amy Wheeless: The whole building is not as well captured. The information is in there.
James Gall: We ignore how it [efficiency] is being funded. Incentives now, but loan
programs in the past.
Ryan Finesilver: We have a team of account executives that look at whole building
systems. This is based on more of a simple payback.
James Gall: We are doing something similar with the Catalyst Building
Doug Howell: Hope this is not outside of the IRP. This area is ripe for innovation.
James Gall: I think AEG is already doing this.
Curtis AEG: Possible to be done, but could do it with other studies.
Dave Van Hersett: Is this a government requirement?
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 372 of 1057
Amy Wheeless: There is a bill that would set large building, non-agriculture or industrial
– $75 million available if it passes.
Jennifer Snyder: TRC for ductless heat pumps. Did we include 2.5? Yes.
Amy Wheeless: Cold weather heat pumps? Yes, available, but they are five to 10 times
more expensive.
Slide 20. TRC goes negative. It doesn’t start at zero from a non-energy saving. Like not
paying to replace LEDs as often UCT never goes negative.
EISA – Energy Security Act of 2005. Next backstop in 2020 forces CFLs and LED is the
difference between 2019 and 2020. Standard practices will make LEDs the default.
Dave Van Hersett: Do we have data yet for pay for performance vs. estimated savings?
AEG Seattle City Light had this in the September GRAC meeting. We have some site
specific information, but didn’t have any numbers in mind. Third party EM&V.

Demand Response Potential Assessment, AEG
Doug Howell: On water heater, doesn’t 1444 require to be DR ready? Port required [on
the water heater] to be DR ready. The study does not capture this yet, since not in law
now.
Jennifer Snyder: What about energy efficiency and demand response overlapping
potential? Following the methodology of the Power Council, energy efficiency goes first.
John Barber: Does this shut off? Yes, but override and signup on insulated tank is
voluntary. Defer reheat until later.
Kurtis Kolnowski: 85% doesn’t apply to DR side, about 25%.
Amy Wheeless: Midwest utilities have been doing more DR when they don’t own
generation. Will even give a free water heater to customers when you agree to let them
control it.
Grant Forsyth (Slide 31): Behavioral – entirely up to the customer. Yes, suggestion.
Amy Wheeless: For the October BC event [natural gas transmission line rupture], did
you send out a gas event? Yes for Oregon. No for the electric side. It was a yes for PSE
for both.
Clint Kalich: What gap is third party contract filling in? Business program targeting
medium to large businesses, getting more energy efficiency since often dealing with a
facility measure with an intermediary.
Phone Participant: Similar impacts both ways, but more popular to have a third party.
We just pay for megawatts. Third party gets it [energy efficicency]. They can do more
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 373 of 1057
hand holding, more cost effective than a utility and have economies of scale doing the
programs with more than one utility.
James Gall: Large industrial customers are not on here, but we are doing back up
generation as non-spinning reserves similar to the PGE program.
Dave Van Hersett: Where does own electric generation fall? Based on our own study.
Would be used as a non-spinning reserve product that we would turn on if all hell
breaks loose.

Pullman Smart Grid Demonstration Project Review, Leona Doege
Dave Van Hersett: What was the population [of this pilot]? 75 installed out of 3,600
single family homes, but 57 to be called out in DR events.
Rachelle Farnsworth: So it was a yearlong program? It Ran from 2012 to August 2014.
Matt Nykiel: Were these only smart thermostat customers in Washington? No, both
Washington and Idaho. Idaho was added back after adding back gas programs.
Rachelle Farnsworth: Were there surveys of customers? Yes, we did a survey. Did you
notice offsets and would you do again? Very unlikely we would do this again, $400
payment for early participants. We used a local contractor who took two hours per
installation.
Grant Forsyth: Any analysis of age bias of who took meters? Early tech adopters, not
necessarily correlated with age.

E3 Study – Resource Adequacy in the Pacific Northwest, James Gall
This assumes the system operates as a single utility.
John Barber: Why not Nevada? It was a choice because at the time of the study, they
were voting on retail choice so they would have operated like California. They have
since voted this down.
Rachelle Farnsworth: Hydro? Same.
Barry Kathrens: Climate, should we assume to be more pessimistic? Assuming same
historical data using 80-year record. May change water shape and make it more volatile
with warming temperatures.
Dave Van Hersett (Slide 22): 2050 baseline is the load we have to meet. Yes.
Jennifer Snyder (Slide 25): So 60% in red can be achieved for little or no cost. Yes,
using the current trajectory for technology.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 374 of 1057
Barry Kathrens: Using constant costs? No, using declining costs.
Dave Van Hersett: Generation and transmission only? Yes.
Jim Le Tellier: What does this compare to California?
AEG: High cost is about what we find in comparison to California.
James Gall: $2,200 to $4,000 to convert to an all-electric home.
Dave Van Hersett: What would drive me out? Cost. Converting all heating to natural gas
and everything else to electric may be a cheaper way to reduce emissions.
Clint Kalich (Slide 22): Interesting how economic. Societally, where should the dollars
be spent? It may be better spent in other areas.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 375 of 1057
2020 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Tuesday, August 6, 2019 Conference Room 130
Topic Time Staff
Introductions and TAC 3 Recap 9:00 Lyons

Washington SB 5116 and IRP Updates 9:10 Lyons Energy and Peak Load Forecast Update 9:30 Forsyth Natural Gas Price Forecast 11:00 Pardee
Lunch 12:00

Electric Price Forecast 1:00 Gall

Existing Resource Overview 2:00 Lyons

Final Resource Needs Assessment 3:00 Lyons Adjourn 4:00

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 376 of 1057
2020 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 377 of 1057
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•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
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 378 of 1057
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 in all or some of the process
•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 studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 at the latest to be able to complete studies in time for publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 379 of 1057
TAC #3 Recap –April 16, 2019
•Introductions and TAC 2 Recap, Lyons
•Regional Legislative Update, Lyons
•IRP Transmission Planning Studies, Rolstad
•Distribution Planning Within the IRP, Fisher
•Conservation Potential Assessment, AEG
•Demand Response Potential Assessment, AEG
•Pullman Smart Grid Demonstration Project, Doege
•E3 Study –Resource Adequacy in the Pacific Northwest, Gall
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-company/integrated-
resource-planning
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 380 of 1057
Today’s Agenda
9:00 –Introductions and TAC 3 Recap, Lyons
9:10 –Washington SB 5116 and IRP Updates, Lyons
9:30 –Energy and Peak Load Forecast Update, Forsyth
11:00 –Natural Gas Price Forecast, Pardee
Noon –Lunch
1:00 –Electric Price Forecast, Gall
2:00 –Existing Resource Overview, Lyons
3:00 –Final Resource Needs Assessment, Lyons
4:00 –Adjourn
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 381 of 1057
Future TAC Topics
•TAC 5: Tuesday, October 15, 2019
–Ancillary services and intermittent generation analysis
–Energy Imbalance Market analysis
–Review Preliminary PRS
–Market scenario results
–Preliminary Portfolio scenario results
•TAC 6: Tuesday, November 19, 2019
–Review of final PRS
–Market scenario results (continued)
–Final Portfolio scenario results
–Carbon cost abatement supply curves
–2020 IRP Action Items
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 382 of 1057
Washington SB 5116 and IRP Updates
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 383 of 1057
Clean Energy Transformation Act (CETA)
•E2SSB 5116 Clean Energy Transformation Act (CETA)
•No coal serving Washington customers after 2025 or earlier
•Carbon neutrality beginning in 2030
–80% or greater clean energy requirement
–Alternate compliance options for up to 20%
–Penalties for non-compliance unless out of utility’s control or for reliability
–Four-year compliance periods beginning with 2030-33
•100% clean energy 2045
•2% incremental cost cap
•Many areas of additional rule making are required and discussed
later
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 384 of 1057
Other CETA Provisions
•A utility extending service to new customers through condemnation must comply with
the clean energy standard and Energy Independence Act (EIA)
•Utilities must assess and plan for obtaining enough funds to meet 60% of low-income
energy assistance need by 2030 and 90% by 2050
•By January 1, 2022, the company must begin filing four-year clean energy
implementation plans with the UTC
•Affirms the UTC authority to use alternative ratemaking mechanisms
•Clarifies the identification of used and useful property during a rate period for up to
four years
•Allows deferred accounting for up to three years for major projects in a utilities clean
energy action plan as part of its IRP
•Allows an imputed return on power purchase agreements of no less than the cost of
debt and no more than the authorized rate of return
•Includes federal incremental hydroelectricity in the definition of an eligible renewable
resource under the EIA
•Extends sales and use tax breaks for renewable resource until 2030 provided specific
labor standards are met
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 385 of 1057
CETA Rule Making
•WUTC opened Docket U-190485 for implementation of legislation passed in the 2019 legislative session
•Phase 0: July 1, 2019 to August 30, 2019
–Initiate rulemaking processes
–Docket U-190531: Inquiry into Valuation of Public Service Company Property Used and Useful after Rate Effective Date
–Timeline finalized after public comment
–Close IRP Rulemaking Docket No. U-161024, incorporate IRP procedural rules, RFP rules and Distributions System Planning in this docket
•Phase 1: August 2019 to January 1, 2021
–Results due by January 1, 2021
•Phase 2: Beginning January 1, 2021
–Results due on or before June 30, 2022
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 386 of 1057
Phase 1
•Publication of social cost of carbon with inflation rate
•Issue policy statement for Valuation of Public Service Company Property Used and Useful after Rate Effective Date (U-190531)
•Start four rulemakings and one policy statement
•IRP Updates
–IRP inputs, structure, public involvement process, outputs of Clean Energy Action Plans, social cost of carbon, equitable distribution of benefits, and assessment informed by cumulative impact analysis
•Used and useful standard policy statement
•EIA rulemaking
–Equitable distribution, definitions of low-income and energy assistance need, low-income efficiency target, and updated hydro eligibility and tracking
•Clean Energy Implementation Plan (CEIP) rulemaking
–Guidelines, equitable distribution of benefits, and incremental cost methodology
•Acquisition rulemaking
–Existing RFP work, ensure new standard met for construction and acquisition of property and the provision of electric service, and resource adequacy
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 387 of 1057
Phase 2 and Additional Projects
Start four rulemakings
1.Cumulative impact analysis
2.Carbon and electricity markets
3.Natural gas conservation
4.Natural gas IRP
Additional projects without statutory deadlines
•Interconnection standard
•Capital budgeting
•Distribution system planning
•Reliability and resiliency
•Demand response policy statement
•Pricing signals policy statement
•Pilot projects policy statement
•Rate making adequacy inquiry
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 388 of 1057
Load and Economic Forecasts: Redux
Grant D. Forsyth, Ph.D.
Chief Economist
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 389 of 1057
Main Topic Areas
•Service Area Economy
•Peak Load Forecast
•Long-run Forecast
2 Painting: Jan Steen, 1640, Netherlands. As the Old Sing, Pipe the Young.Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 390 of 1057
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 391 of 1057
Distribution of Employment: Services and
Government are Dominant
Source: BLS, BEA and author’s calculations.4
Farm
2%
Private Goods
14%
Private Services
66%
Local
11% (61%)
State
4% (21%)
Federal
2%(9%)
Military
1%(8%)
Other
18%
WA-ID MSA Employment, 2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 392 of 1057
Non-Farm Employment Growth, 2009-2019
Source: BLS and author’s calculations.5
-6%
-4%
-2%
0%
2%
4%
6%
Ju
n
-
0
9
Se
p
-
0
9
De
c
-
0
9
Ma
r
-
1
0
Ju
n
-
1
0
Se
p
-
1
0
De
c
-
1
0
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r
-
1
1
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n
-
1
1
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p
-
1
1
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c
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r
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1
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1
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p
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1
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1
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p
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c
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1
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r
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1
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1
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p
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1
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c
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r
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1
6
Ju
n
-
1
6
Se
p
-
1
6
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c
-
1
6
Ma
r
-
1
7
Ju
n
-
1
7
Se
p
-
1
7
De
c
-
1
7
Ma
r
-
1
8
Ju
n
-
1
8
Se
p
-
1
8
De
c
-
1
8
Ma
r
-
1
9
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 Since June 2009
Avista WA-ID MSAs U.S.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 393 of 1057
Non-Farm Employment: Finally Catching Up
Source: BLS and author’s calculations.6
90
95
100
105
110
115
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
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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
-
1
3
Ap
r
-
1
4
Au
g
-
1
4
De
c
-
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
No
n
-Fa
r
m

E
m
p
l
o
y
m
e
n
t

D
e
c

2
0
0
7
=
1
0
0
Non-Farm Employment Level Since 2007 (Dashed Shaded Box = Recession Period)
Avista WA-ID MSAs U.S.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 394 of 1057
Population Growth: Recovering with
Employment Growth
Source: BEA, U.S. Census, and author’s calculations.7
1.9%
1.4%
1.2%
0.8%
0.5%0.5%
0.7%
1.0%
1.2%
1.7%
1.9%
1.8%
1.0%1.0%0.9%0.8%0.7%0.7%0.7%0.7%0.7%0.7%0.6%0.6%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
An
n
u
a
l

G
r
o
w
t
h
Population Growth in Avista WA-ID MSAs
Total Spokane+Kootenai+Nez Perce-Asotin, WA-ID MSA Pop. Growth U.S. Pop. Growth
Proxy for
Customer
Growth
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 395 of 1057
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 396 of 1057
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial
loads.
•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 was recently
recalibrated to allow GDP impact to differ between winter and summer.The
historical impacts of DSM programs are “trended” into the forecast.
•The coefficients of the model are used to generate a distribution of peak loads
by month based on historical max/min temperatures, holding GDP constant.
An expected peak load can then be calculated for the current year (e.g., 2019).
Model confirms Avista is a winter peaking utility for the forecast period;
however, the summer peak is growing at a faster than the winter peak.
•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.
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 397 of 1057
GDP Growth Assumptions: 2019 IRP vs. 2017 IRP
10 Source: Various and author’s calculations.
2.5%
1.9%1.8%1.8%1.9%
2.1%2.1%2.1%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
2019 2020 2021 2022 2023
An
n
u
a
l

G
r
o
w
t
h
2019 GDP Growth 2017 GDP IRP Growth
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 398 of 1057
Current Peak Load Forecasts for Winter and
Summer, 2019-2045
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 2019-45
Winter 0.34%
Summer 0.44%
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 399 of 1057
Current and Past Peak 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 2019 IRP
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 400 of 1057
Current and Past Peak Load Forecasts for
Summer Peak, 2011-2045
1,250
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
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2019 IRP13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 401 of 1057
Long-Term Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 402 of 1057
Basic Forecast Approach
2019
Time
2024 20452025
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.
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
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 403 of 1057
The Long-Term Residential Relationship, 2020-
2040
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as
population growth, 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.
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 404 of 1057
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
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 Residential Customer Growth Rates
2019 IRP Residential Customer Growth 2017 IRP Residential Customer Growth
Average annual growth rate from
2020-2045 = 0.78%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
Medium Term Long Term
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 405 of 1057
Residential Solar Penetration, 2008-2018
0.00%
0.05%
0.10%
0.15%
0.20%
0.25%
305,000 310,000 315,000 320,000 325,000 330,000 335,000 340,000 345,000
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
18
2008
2014
2015
2016
2017
2018
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 406 of 1057
Residential Solar Penetration, 2020-2045
19
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
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
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental Solar Customers
2017 IRP Base-Line Residential Solar Customers 2019 IRP Base-Line Residential Solar Customers
Current penetration is 0.25% and typical
size is 7,800 watts. By 2045, penetration
will be near 2.2% of residential customers
and average size of installed systems will
be 10,000+ watts.
Penetration was near 0.5% of
residential customers and average size
of installed systems was 6,000 watts.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 407 of 1057
Residential EVs/PHEVs, 2020-2045
0
20,000
40,000
60,000
80,000
100,000
120,000
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
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2017 IRP Projected EV/PHEV 2019 IRP Projected EV/PHEV
Current ≈ 800
Forecast By 2045 Prob.
Low 45,000 50%
Middle 100,000 30%
High 250,000 20%
Weighted Average 103,000
20
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 408 of 1057
Residential EVs/PHEVs by Household Income
21 Source: EIA, Today in Energy, May 2018. Regional data from U.S. Census
Spokane +
Kootenai
12%Spokane +
Kootenai
7%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 409 of 1057
EV/PHEV Gasoline CO2 Savings Avista
Service Territory
0
100,000
200,000
300,000
400,000
500,000
600,000
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
Estimated EV/PHEV Gasoline CO2 Reduction in Metric Tons
Estimated with DOE data. Assumes 5.18
metric tons of C02 per gasoline vehicle.
Savings = Number of EV/PHEV x 5.18
22
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 410 of 1057
Native Load Forecast, 2020-2045
900
950
1,000
1,050
1,100
1,150
1,200
1,250
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
Native Load Forecast (no CWTR), Average Megawatts
2019 IRP Native Load Base-Line, No CWTR 2017 IRP Base-Line Native Load, No CWTR
2015 IRP Base-Line Native Load, No CWTR
Medium Term Long Term
23
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 411 of 1057
Net Solar and EV/PHEV Impact, 2020-2045
-5
0
5
10
15
20
25
30
35
40
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
aM
W
aMW Impact of Solar and EV/PHEV
2019 IRP Solar aMW (Load Reduction)2019 IRP EV/PHEV aMW (Load Addition)
2019 Net IRP Solar and EV/PHEV Impacts aMW
Long TermMedium Term
24
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 412 of 1057
Native Load Growth Forecast, 2020-2045
-0.2%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
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
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2019 IRP Base-Line Native Load Growth 2017 IRP Base-Line Native Load Growth25
EV/PHEV “Bend”
IRP Avg. Annual
Growth
2019 IRP 0.3%
2017 IRP 0.5%
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 413 of 1057
Residential UPC Growth: 2020-2045
26
-2.00%
-1.50%
-1.00%
-0.50%
0.00%
0.50%
1.00%
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
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth
2019 IRP Residential Base-Line UPC Growth
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 414 of 1057
Long-Term Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
27
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 415 of 1057
Monthly Conservation as a Share of Total
Actual Retail Load: Navigant Estimates
28
Ratio = 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑦𝑦𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸,𝑌𝑌𝐸𝐸𝐸𝐸𝐶𝐶𝑌𝑌
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
Ja
n
-
9
9
Au
g
-
9
9
Ma
r
-
0
0
Oc
t
-
0
0
Ma
y
-
0
1
De
c
-
0
1
Ju
l
-
0
2
Fe
b
-
0
3
Se
p
-
0
3
Ap
r
-
0
4
No
v
-
0
4
Ju
n
-
0
5
Ja
n
-
0
6
Au
g
-
0
6
Ma
r
-
0
7
Oc
t
-
0
7
Ma
y
-
0
8
De
c
-
0
8
Ju
l
-
0
9
Fe
b
-
1
0
Se
p
-
1
0
Ap
r
-
1
1
No
v
-
1
1
Ju
n
-
1
2
Ja
n
-
1
3
Au
g
-
1
3
Ma
r
-
1
4
Oc
t
-
1
4
Ma
y
-
1
5
De
c
-
1
5
Ju
l
-
1
6
Fe
b
-
1
7
Se
p
-
1
7
Ap
r
-
1
8
No
v
-
1
8
Ra
t
i
o

o
f

C
o
n
s
e
r
v
a
t
i
o
n

t
o

K
W
H

L
o
a
d

Energy Crisis
ARRA
Increased
Conservation
Activity
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 416 of 1057
Median Monthly Conservation as a Share of
Total Actual Retail Load: Navigant Estimates
29
Median Ratio Month t = Median𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝐸𝐸𝐸𝐸𝐸𝐸𝐶𝐶𝐶𝐶𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸𝐴𝐴𝐴𝐴𝐸𝐸𝐴𝐴𝐸𝐸𝐴𝐴𝐾𝐾𝐾𝐾𝐾𝐾𝐿𝐿𝐶𝐶𝐸𝐸𝐸𝐸𝑀𝑀𝐶𝐶𝐶𝐶𝐸𝐸𝑀𝐸𝐸, excluding 2001
0.797%
0.693%
0.769%0.730%0.742%
0.816%0.856%
0.722%
0.661%
0.779%0.765%0.800%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Me
d
i
a
n

C
o
n
s
e
r
v
a
t
i
o
n

t
o

L
o
a
d

R
a
t
i
o
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 417 of 1057
Comparison of Native Load Forecasts, 2020-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
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
aM
W
aMW Load Comparision with Conservation
Base-Line Native Load Base-Line Native Load with Conservation Added Back30
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 418 of 1057
Natural Gas
Tom Pardee, Manager of Natural Gas Planning
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 419 of 1057
Agenda
•Market Dynamics
•Pipeline Transportation
•Renewable Natural Gas (RNG)
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 420 of 1057
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 421 of 1057
Canada
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 422 of 1057
Canada Natural Gas Production
Alberta 15
Bcf per day
British Columbia
0.5 Bcf per day
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 423 of 1057
300 Years of resources at current levels
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 424 of 1057
AECO cash vs. forwards
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 425 of 1057
Canadian Natural Gas Storage
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 426 of 1057
LNG Canada
Source: https://www.lngcanada.ca/about-lng-canada/
Daily liquefaction:
3.5 Bcf Or
1,025,749 MWh
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 427 of 1057
US
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 428 of 1057
US Natural Gas Production
11 Source: EIA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 429 of 1057
80 Years of resources at current levels
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 430 of 1057
Henry Hub cash vs. forwards
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 431 of 1057
US Natural Gas Storage
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 432 of 1057
15
-14
-7
0
7
14
21
28
-5
0
5
10
2000 2010 2020 2030 2040 2050
Natural gas trade (Reference case)
trillion cubic feet
2018
history projections liquefied natural
gas (LNG)
exports
pipeline exports to
Mexico
Canada
pipeline imports
from
Canada
LNG imports
billion cubic feet per day
Source: EIA AEO 201915
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 433 of 1057
2020 IRP Henry Hub Natural Gas Price
Forecast: 2021-2040: $3.99 per Dth
16
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
$
p
e
r

D
t
h
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 434 of 1057
Pipeline Transportation
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 435 of 1057
Fugitive Emissions
•Unintended emissions from facilities or activities
(e.g., construction) that "could not reasonably
pass through a stack, chimney, vent, or other
functionally equivalent opening."
Fugitive emissions estimated at
0.783%
*This figure includes all
emissions from production,
transport & lost and
unaccounted for gas
Source –NEB for Canadian infrastructure and EIA for US infrastructure18
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 436 of 1057
GTN & NWP Fully Subscribed
•Contractually both pipelines are now fully
subscribed.
•Canadian producers signed up for new contracts in
order to get natural gas out of Canada and into
more lucrative markets.
GTN
NWP
19
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 437 of 1057
Avista Transport for Electric Generation
20
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 438 of 1057
AECO
Lancaster 49,000
Rathdrum 43,600
Boulder 5,400
98,000 DTh/Day*
Coyote Springs
53,550 DTh/Day*Stanfield
Malin
Pipeline Capacity
60,592 DTh/Day
Pipeline Capacity
26,388 DTh/Day
Current Transport & Gas Generation
* Based on the non-
coincidental winter peak-day
Boulder: 5,400
Coyote: 53,550
Lancaster: 49,000
Rathdrum: 43,600
Total: 151,550
Firm Rights: 60,592
Shortfall: 90,958
21
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 439 of 1057
Renewable Natural Gas (RNG)
22
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 440 of 1057
Source: Promoting RNG in WA State
23
RNG Process Overview
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 441 of 1057
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 HillsLandfill(KingCounty)
RooseveltLandfill(RepublicServices)KlickitatCountyPUD
SouthTreatmentPlant (KingCounty)PugetSoundEnergy
Landfills Wastewatertreatmentplants
Dairydigesters Municipalfood wastedigesters
Foodprocessingresiduals
Foodprocessedat compostfacilities
Landfills Wastewatertreatmentplants
Dairydigesters Municipalfood wastedigesters
Dth
Existing Projects
Near Term Projects
Medium Term Projects
24
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 442 of 1057
WA RNG Potential Bcf dth dth/day
Current 3.9 4,002,400 10,965
Near-Term 5.2 5,395,010 14,781
Mid-Term 5.6 5,729,010 15,696
Total 14.7 15,126,420 41,442
Avista Natural Gas Consumption
Avista Power Load 2018 23.4 24,114,712 66,068
Avista LDC Load 2018 33.4 34,456,500 94,401
Total Avista Consumption 58,571,212 160,469
Gas Consumption of CS2 50,000
North American Gas Reserves
Canadian Gas Reserves (300 years)1,828,891 1,885,586,517,900
U.S. Gas Reserves (80 years)2,459,000 2,535,229,000,000
Total NA Gas Reserves 4,287,891 4,420,815,517,900
WA RNG Potential Share of NA Gas Reserves 0.0003%
Renewable Natural Gas Comparison to Non-Renewable
Natural Gas Reserves
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 443 of 1057
Total Potential Annual Production = 32 Bcf
NREL Estimates –Idaho RNG
Source –Anaerobic
Landfills 3,712,221
Wastewater Treatment 6,196,531
Agriculture Manure 20,220,571
Source-Separated Organics (Solid Waste)2,311,354
Total 32,440,676
National Renewable Energy Laboratory, NREL Biofuels Atlas
26
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 444 of 1057
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
27
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 445 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 446 of 1057
2020 IRP Electric Market Price Forecast
James Gall, IRP Manager
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 447 of 1057
Our Region
2 Source: NERC
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 448 of 1057
-
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Coal Geothermal Hydroelectric ConventionalNatural Gas Nuclear OtherOther Biomass Other Gases PetroleumPumped Storage Solar Thermal and Photovoltaic WindWood and Wood Derived Fuels
US Western Interconnect Generation
3 Source: EIA Data
Coal
Hydro
Natural Gas
Wind
Nuclear
Solar
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 449 of 1057
13
23 23
117
126
22
38 42
58
45
51
59
32 33
23 19
32 33
23 20 22
30 36
27 31 33 34
$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
$
p
e
r

M
W
h
Mid-Columbia Flat Firm Price Index History
Energy Crisis
Natural Gas Market Tightens
Shale DevelopmentCheap Natural
Gas, good
hydro
Forwards
as of July
29, 2019
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 450 of 1057
2018 Fuel Mix Comparison (NW vs West)
US Western Interconnect Northwest Four States
5 Source: EIA Data
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 451 of 1057
Natural Gas vs. On-Peak Electric Prices
(2003-19)
6
$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
2018 & 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 452 of 1057
Market Indicators
7
-$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
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
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
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
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M
W
h
Daily Price Standard Deviation
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 453 of 1057
Western Greenhouse Gas Emissions Power Industry
Source: EPA
Adjusted for plants in the Western Interconnect system8
1980: 185 MMT
1990: 227 MMT
2008: 307 MMT
2017: 228 MMT
1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017
WY 22 20 17 15 19 24 17 26 27 25 28 27 30 29 31 28 29 29 31 30 31 31 30 30 30 29 29 30 30 30 29 26 29 31 30 29 29 29
WA 8 8 6 7 7 8 5 8 9 9 7 8 10 10 12 8 11 9 12 11 14 14 12 14 14 14 10 12 13 13 13 7 6 12 12 11 9 10
UT 11 11 11 11 12 14 15 25 27 28 29 28 30 31 32 30 30 31 32 33 33 33 34 35 35 36 36 38 39 36 35 34 32 35 34 33 28 27
OR 1 2 1 1 1 1 - - - 1 2 4 4 4 5 3 3 3 6 6 7 9 7 8 8 8 6 10 10 9 10 6 7 9 8 9 8 7
NM 20 19 21 24 23 24 21 23 24 26 25 21 24 25 26 25 26 27 27 28 29 28 27 29 29 30 30 29 28 28 25 26 25 24 21 20 19 19
NV 11 13 14 13 15 12 16 15 18 17 17 18 19 18 20 18 20 19 21 22 25 24 21 23 25 26 17 17 18 18 17 15 15 15 16 14 14 12
MT 5 5 4 3 8 8 11 12 16 16 15 16 17 14 17 16 13 15 17 17 16 17 16 17 18 18 18 19 19 16 19 16 15 16 16 17 16 14
ID - - - - - - - - - - - - - - - - - 0 0 0 0 1 0 1 1 1 1 1 1 1 1 0 1 1 1 1 1 1
CO 21 23 24 23 25 27 26 27 28 30 31 30 31 32 33 32 34 34 35 36 39 41 40 40 40 41 42 43 41 38 40 39 39 39 38 37 37 36
CA 61 59 38 31 34 40 27 37 37 44 40 38 46 42 50 37 33 36 39 43 53 58 44 43 46 42 47 50 51 48 44 36 48 46 46 44 37 28
AZ 25 31 31 26 29 31 25 27 29 35 33 33 35 37 38 32 32 35 38 40 45 46 45 46 52 51 53 55 58 52 54 52 51 55 53 50 47 45
0
50
100
150
200
250
300
350
Mi
l
l
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n

M
e
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c

T
o
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s
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 454 of 1057
Northwest Greenhouse Gas Emissions
MT WA OR ID
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 455 of 1057
3rd party software-Aurora by Energy Exemplar
Electric market fundamentals-production cost
model
Simulates generation dispatch to meet 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
Electric Market Modeling
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 456 of 1057
Stochastic Approach
Simulate Western Electric market hourly for next 25
years (2021-45)
–That is 175,248 hours for each study
Model 500 potential outcomes
–Variables include fuel prices, loads, wind, hydro, outages, and
inflation
–Simulating 87.6 million hours
Run time is about 14+ days on 20 processors
Why do we do this?
–Allows for complete financial evaluation of resource alternatives
–Without stochastic prices we cannot account for tail risk
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 457 of 1057
Modeled Western Interconnect Topology
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 458 of 1057
How Aurora derives hourly prices
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
13 Note: minimum price is negative $25/ MWh (2018$)Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 459 of 1057
Approach to New Resource Selection
•Baseline
–3rd party consultant new resource outlook
–known retirements
•Policy Constraints
–California, BC, and Alberta include CO2 price adder
–OR: Emissions Cap (3.6 million tons)
–WA: CETA: resources & social cost of carbon
–ID: Clean Power Plan Emission’s Intensity (delayed)
–No new coal-fired generation
–Uses existing state Renewable Portfolio Standards
•Resource Adequacy
–Achieve close to 1-in-20 loss of load probability (LOLP/LOLE)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 460 of 1057
2019 2020 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
Geothermal - - -90 70 24 76 104 52 104 26 104 26 104 26 104 26 104 76 114 86 124 96 134 140 156 160
Biomass - - -18 11 35 36 35 37 35 36 36 36 34 34 37 34 34 36 35 36 34 34 37 34 34 36
Hydro - - -182 40 19 23 30 29 25 29 30 28 40 31 36 39 58 51 56 54 51 58 56 56 56 58
Consumer Gen - - -3,092 357 367 378 390 402 414 427 439 452 466 480 494 510 525 541 557 574 592 610 628 647 667 687
Storage - - -1,267 551 659 667 587 480 480 331 671 660 748 795 849 897 941 1,050 1,308 1,358 1,500 1,600 1,598 1,600 1,601 1,600
Wind - - -3,522 445 419 215 640 846 896 993 1,070 1,095 1,070 1,462 1,236 1,450 1,632 2,078 3,145 4,127 3,308 3,399 4,576 3,510 5,656 3,294
Solar 3,400 3,400 3,400 6,102 3,915 4,304 3,676 3,582 3,195 3,082 4,313 5,029 1,662 2,562 3,778 3,834 3,539 3,320 2,240 3,367 2,583 7,705 4,168 3,985 5,079 5,052 8,910
NG Peaker 2,353 2,353 2,353 350 988 -880 1,422 -175 1,467 350 350 - - -1,230 175 440 175 587 412 237 400 175 1,111 1,659
NG CCCT 371 371 371 1,200 1,200 800 400 800 429 -400 1,200 300 400 829 -829 829 400 1,200 800 2,516 3,403 1,716 2,574 2,945 3,403
-
5,000
10,000
15,000
20,000
25,000
Me
g
a
w
a
t
t
s

o
f

C
a
p
a
c
i
t
y
New Resources Forecast-US West
Natural Gas: 49 GW
Wind: 50 GW
Solar: 110 GW
Storage: 24 GW
Customer: 15 GW
Other: 4 GW
15
Note 1: 2019-2021 additions are spread evenly between the 3 years,
these are all added in 2021 for modeling purposes
Note 2: Storage is assumed to be a blend of technologies, average of 3
hours duration in 2021, ramping to 6 hours average duration by 2045
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 461 of 1057
2019 2020 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
Geothermal 19 19 19 -24 26 54 26 54 26 54 26 54 26 54 26 54 26 54 26 54 26 54 60 66 70 72
Biomass - - -11 11 10 11 11 11 10 12 10 10 10 11 10 10 10 11 10 10 10 11 10 10 10 11
Hydro 58 58 58 31 11 13 13 14 12 13 13 14 16 15 15 18 19 19 19 18 19 19 19 18 19 19 18
Consumer Gen 36 36 36 11 11 12 12 13 13 14 14 14 15 15 16 17 17 18 19 19 20 21 22 23 23 25 26
Storage - - -42 86 85 86 51 51 52 52 51 50 52 60 60 60 116 213 215 214 214 213 214 213 214 214
Wind 219 219 219 70 69 4 231 337 408 439 454 462 358 270 200 199 379 537 408 619 1,100 732 1,692 772 874 1,280 898
Solar 362 362 362 501 694 77 966 2,169 2,167 678 719 2,863 167 1,345 1,680 1,081 528 869 310 853 254 3,555 643 305 361 618 3,105
NG Peaker - - - - - -880 - - -880 175 - - - -880 -440 - - - - - - - -
NG CCCT - - - - - - - - - -400 400 300 - - - - - - - - - - -429 400 -
-
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

o
f

C
a
p
a
c
i
t
y
New Resources Forecast-Northwest States
Natural Gas: 5 GW
Wind: 13 GWSolar: 27 GW
Storage: 3 GW
Customer: 0.5 GW
Other: 2 GW
16
Note 1: 2019-2021 additions are spread evenly between the 3 years,
these are all added in 2021 for modeling purposes
Note 2: Storage is assumed to be a blend of technologies, average of 3
hours duration in 2021, ramping to 6 hours average duration by 2045
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 462 of 1057
Resource Type Mix Forecast
(US Western Interconnect)
17
DRAFT
Fuel Type 2045 minus 2018aGW
Natural Gas -14.7
Hydro +1.4
Solar +28.7
Wind +14.9
Other +0.9
Coal -13.2
Nuclear -4.1
-
20,000
40,000
60,000
80,000
100,000
120,000
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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 463 of 1057
Resource Type Mix Forecast
(NW States)
18
DRAFT
Fuel Type 2045 minus 2018aGW
Natural Gas -2.8
Hydro*-1.1
Solar +2.8
Wind +3.6
Other +0.7
Coal --1.9
Nuclear -1.1
Note: Hydro change is due to actual hydro vs. average hydro
-
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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 464 of 1057
Stanfield Natural Gas Price Forecast
20-year levelized price: $3.98/Dth
25-year levelized price: $4.66/Dth
Note: Coefficient of variation (stdev/mean) in 2021 is 13%, in 2040, the volatility increases to 32%19
DRAFT
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
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
$
p
e
r

D
e
k
a
t
h
e
r
m
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 465 of 1057
Mid-Columbia Electric Price Forecast
(Deterministic)
20
DRAFT
Levelized Prices
20 year 25 year
Flat: $25.03/MWh $26.06/MWh
On Peak: $25.07/MWh $25.92/MWh
Off Peak: $24.99/MWh $26.25/MWh
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
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
$
p
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M
W
h
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 466 of 1057
Mid-Columbia Electric Price Forecast
(Stochastic Flat Price Statistics)
Note: Coefficient of variation (stdev/mean) in 2021 is 28%, in 2040, the volatility increases to 42%21
DRAFT
20yr Levelized: $26.39 per MWh, 25 yr Levelized: $27.79 per MWh
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
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
$
p
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W
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 467 of 1057
Historical IRP Price Forecasts
(Annual Flat Prices)
22
DRAFT
Note: * Represents IRP forecast expected cases without carbon “taxes” in plant dispatch
$
p
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M
W
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 468 of 1057
Hourly Price Shape
23
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
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M
W
h
Hour
2025 Mid Columbia Average Prices-Avg: $22.83
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 469 of 1057
Hourly Price Shape
24
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
r

M
W
h
Hour
2030 Mid Columbia Average Prices-Avg: $25.17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 470 of 1057
Hourly Price Shape
25
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
r

M
W
h
Hour
2035 Mid Columbia Average Prices-Avg: $31.44
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 471 of 1057
Hourly Price Shape
26
DRAFT
-$50
$0
$50
$100
$150
$200
$250
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
r

M
W
h
Hour
2040 Mid Columbia Average Prices-Avg: $33.70
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 472 of 1057
Hourly Price Shape
27
DRAFT
-$50
$0
$50
$100
$150
$200
$250
$300
$350
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
r

M
W
h
Hour
2045 Mid Columbia Average Prices-Avg: $40.00
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 473 of 1057
0%
5%
10%
15%
20%
25%
30%
35%
40%
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
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Wind: Deterministic Solar: Deterministic
Wind: Stochastic Solar: Stochastic
Renewable Curtailments
2030: 0% to 5% curtailment
2045: 14% to 17% curtailment
2030: 4% to 9% curtailment
2045: 10% to 32% curtailment
Note: Both wind and solar use a -$8.00/MWh + inflation variable charge + PTC if available Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 474 of 1057
Greenhouse Gas Emissions Forecast
(US Western Interconnect Total)
29
DRAFT
Mi
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M
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T
o
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s
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 475 of 1057
Greenhouse Gas Emissions Forecast
(Northwest-WA,OR,ID,MT)
30
DRAFT
-
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 476 of 1057
-
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
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
LO
L
H
LO
L
P
Regional Resource Adequacy
31 Resource adequacy results are not detailed enough to judge regional resource
adequacy and are used for price forecasting only
2021 EUE:
392 MWh
2030 EUE:
51 MWh
2040 EUE:
743 MWh
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 477 of 1057
Electric Price Forecast Scenarios
•Social Cost of Carbon in Dispatch
•No CETA resource build
•Low Natural Gas Prices
•High Natural Gas Prices
32
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 478 of 1057
Social Cost of Carbon Price Forecast
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
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
$
p
e
r

M
e
t
r
i
c

T
o
n
2007 $Nominal
Note: Inflation from 2007 uses CPI between 2007 and 2018, then 2% per year33
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 479 of 1057
Scenario Price Forecast Results
Expected Case- Deterministic Scenario: No CETA
Scenario: SCC Scenario: Low NG Prices
Scenario: High NG Prices
34
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 480 of 1057
Scenario Levelized Prices
$26.06 $27.32
$45.71
$18.27
$36.10
$28.74 $30.12
$50.41
$20.15
$39.81
$0
$10
$20
$30
$40
$50
$60
Expected Case-
Deterministic
Scenario: No CETA Scenario: SCC Scenario: Low NG
Prices
Scenario: High NG
Prices
$
p
e
r

M
W
h
20 yr 25 yr
35
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 481 of 1057
US Western Interconnect
Generation Mix Forecast by Scenario
(2040)
Expected Case-Deterministic Scenario: No CETA Scenario: SCC Scenario: Low NGPrices Scenario: High NGPrices
Natural Gas 13.0 13.5 7.7 13.9 12.9
Solar 28.9 28.1 27.9 28.8 28.9
Wind 16.7 16.7 28.3 16.6 16.7
Nuclear 4.2 4.2 4.0 4.2 4.2
Coal 5.9 6.0 1.6 5.2 6.1
Hydro 21.7 21.7 21.7 21.7 21.7
Other 4.4 4.4 3.4 4.4 4.3
-
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
36
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 482 of 1057
GHG Emission Forecast
US Western Interconnect
Expected Case- Deterministic
Scenario: No CETA
Scenario: SCC
Scenario: Low NG Prices
Scenario: High NG Prices
Northwest
Expected Case- Deterministic
Scenario: No CETA
Scenario: SCC
Scenario: Low NG Prices
Scenario: High NG Prices
37
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 483 of 1057
Colstrip Dispatch
38
Ca
p
a
c
i
t
y

F
a
c
t
o
r
DRAFT
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 484 of 1057
Existing Thermal Resource Overview
Darrell Soyars, Manager of Corporate Environmental Compliance
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 485 of 1057
Purpose
•Review major environmental regulatory programs that may impact
current and future operations
•This is not intended to be a discussion or debate about past
practices or current approach to achieve compliance with these
programs
•Questions are welcome within the scope of this presentation
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 486 of 1057
Colstrip Environmental Considerations
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 487 of 1057
Colstrip Ownership Information
4
Colstrip Basic Data Colstrip Ownership Percentages
Colstrip
Unit #
Size
(MW)
Year
Online
Avista NorthWestern
Energy, LLC
PacifiCorp Portland
General
Electric
Talen
Energy,
LLC
Puget
Sound
Energy
Unit #1 333 1975 0%0%0%0%50%50%
Unit #2 333 1976 0%0%0%0%50%50%
Unit #3 805 1984 15%0%10%20%30%25%
Unit #4 805 1986 15%30%10%20%0%25%
Total 2,094 11%11%7%14%25%32%
•Generating Units 1 and 2: 333 MW each scheduled to shut down end of
2019, required to shut down by July 2022
•Generating Units 3 and 4: 805 MW each
•Assumed to operate until 2040, depreciation varies by owner
•Will not be serving Washington loads after 2025
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 488 of 1057
Air Quality –Montana Mercury Rule
•Program established 2010, mercury site-wide annual average below
0.9 lb/Tbtu
•Colstrip installed mercury oxidizer/sorbent injection system in 2010
•MDEQ recently concurred with our pollution equipment technology
review
•Units 3 & 4 operate in the 0.8 lb/Tbtu range
•No major changes expected
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 489 of 1057
Air Quality –Mercury Air Toxics Rule
Mercury Air Toxics (MATS) Rule:
•Program established 2016
•Particulate Matter (PM) used as a surrogate for air toxics
•PM site-wide 30-day rolling average below 0.030 lb/MMBtu
•PM and mercury are controlled by existing wet scrubbing equipment with injection
•Units 3 & 4 typically operate in the 0.024 lb/MMBtu range
•Both units exceeded permit limitations during second quarter testing in June 2018
•Root cause analysis led to corrective actions; reachieved compliance in September 2018
•Expect MDEQ penalty for emissions exceedances
•No major changes expected
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 490 of 1057
Air Quality –Regional Haze Rule
•Program established 1999, Improve visibility in Class 1 areas
•Federal plan for Montana was vacated by courts in 2015
•NOx is controlled by LoNOx burners, Overfire air and Smartburn
•MDEQ issued progress plan in 2017, now ready to take leadership of
program
•Request for Colstrip analysis due in late 2019 for next planning period
•Regional unit shutdowns would indicate that emissions are below glide
path
•No changes or additional pollution controls expected
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 491 of 1057
Air Quality
•Affordable Clean Energy (ACE) Rule
–Program established 9/16/19, replacement for Clean Power Plan (CPP)
•Reduce CO2 emissions by Heat Rate Improvements (HRI)
•MDEQ will determine future limitations based on evaluation of HRI technologies
•Cost and remaining useful life consideration
•MDEQ must submit plan by July 2022, unit compliance by 2024
•Impacts are unknown at this time
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 492 of 1057
Water Use
•Raw water is withdrawn from the Yellowstone River to Castle Rock Lake (a.k.a., the Surge Pond) via a 29-mile long pipeline.
•From the Surge Pond, water is piped to holding tanks at the Plant Site for use in boilers, cooling towers and scrubber systems.
•Fly ash from the scrubber system is transported to paste plants which remove excess water and deposit paste in disposal cells.
•Bottom ash is transported to holding ponds, dewatered, and then transported to disposal cells for evaporation.
•Clearwater from paste plants and dewatering is recirculated for reuse.
•All water is reused or lost through evaporation -Zero discharge facility.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 493 of 1057
Three Storage Areas
–The Plant Site contains Generating Units 1 through 4 and several associated ponds (Avista share)
–The Units 3 & 4 EHP contains several ponds for the disposal of fly ash scrubber slurry/paste from Generating Units 3 and 4, and bottom ash from Generating Units 1 through 4, and is located approximately 2.5 miles southeast of the Plant Site. (Avista share)
–The Units 1 & 2 SOEP/STEP contains several ponds for the disposal of fly ash scrubber slurry/paste from Generating Units 1 and 2, and is located approximately 2 miles northwest of the Plant Site. (No Avista share)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 494 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 495 of 1057
Management Drivers
•Regulatory programs
–The Site Certificate originally issued including the amended 12(d) stipulation under the Major Facility Siting Act in Montana, Nov. 1975.
–Administrative Order on Consent (AOC) Regarding Impacts Related to Wastewater Facilities, MDEQ (July 2012), Settlement agreement entered (2016).
–Federal Coal Combustion Residual (CCR) Rule, 40 Code of Federal Regulations (CFR), April 2015.
•Operational facility
–Units 1 and 2 announced early shutdown at the end of 2019.
–Units 3 and 4 must maintain on-going operations
–Convert to dry ash storage by the end of 2022.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 496 of 1057
Strategic Water Planning
•Master Plan originally developed in November 2015, Executive
Summary (Sept. 2016) is available on MDEQ-AOC website:
•http://deq.mt.gov/DEQAdmin/mfs/ColstripSteamElectricStation
•AOC public process will select actions to be performed and requires
Financial Assurance (FA) of approved plan amounts.
•AOC Process>Site Characterization>Cleanup Criteria and Risk
Assessment>Remedy Evaluation>Implement the selected remediation
•CCR Requirements tracking:
•https://www.talenenergy.com/generation/fossil-fuels/ccr-colstrip
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 497 of 1057
Plant Site Ponds
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 498 of 1057
Colstrip Units 3 & 4 Evaporative Ponds
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 499 of 1057
Major Water Activities
•Must remove Boron, Chloride and Sulfate in groundwater
•Achieve source control
–Close existing ash storage ponds
–Build water treatment system
–Dry ash storage
•Install and operate groundwater treatment system
•Achieve clean-up criteria
•Must take place regardless of plant operation
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 500 of 1057
Avista’s Financial Assurance Share
•Plant Site area
–Remedy Plan –$5,841,000 posted 12/21/18
–Closure Plan –$383,713 posted 2/1/19
•Units 3 & 4
–Remedy Plan –currently under review, expected late 2019
–Closure Plan – $6,793,050 posted 2/1/19
•Annual bond reconciliation required
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 501 of 1057
Colstrip Fuel Contract
•Coal supplier has emerged from bankruptcy and agreed to honor the current
contract, which ends 12/31/19
•New contract is being negotiated and results will be used to model Colstrip in
this IRP
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 502 of 1057
Modeled Colstrip Costs
19
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Fixed O&M 10.3 9.4 9.7 10.1 11.2
Coal Combustion Residuals O&M 0.4 0.6 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9
Existing Capital Revenue Requirement –WA 12.1 11.3 10.5 9.8 9.1 0.4
Existing Capital Revenue Requirement –ID 5.9 5.5 5.1 4.8 4.5 4.2 3.9 0.2
Traditional Capital Spending (Expensed)9.4 3.2 4.2 9.5 6.4
Asset Retirement Obligation Capital Revenue Requirement 1.7 1.7 1.6 1.6 1.5 1.5 1.4 1.4 1.3 1.3
Coal Combustion Residuals
Master Plan Capital Revenue Requirement 0.5 0.6 0.9 1.1 1.1 1.0 1.0 1.0 0.9 0.9
Total 40.3 32.3 32.9 37.8 34.7 8.0 7.2 3.5 3.1 3.1
Table does not include fuel and variable O&M costs
Coal Combustion Residuals O&M and Master Plan Capital Revenue Requirement, and Asset Retirement
Obligation Capital Revenue Requirement continue through 2045 Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 503 of 1057
Lancaster Power Purchase Agreement
•Current PPA ends in October 2026
•Directly connect to either AVA or BPA transmission system
•Avista controls firm GTN transportation rights
•This IRP will evaluate an extension of this contract
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 504 of 1057
Thermal Plant Book Value and Remaining Depreciation
21
Thermal Plant Book Value
(millions)
Remaining Life
(years)
Boulder Park $ 17.4 20
Colstrip Units 3 and 4 $ 121.4 See Note
Coyote Springs 2 $ 124.8 21
Kettle Falls CT $ 3.7 24
Northeast $ 0.6 <2
Rathdrum $ 36.5 14
•This table includes land, total generation and transmission/interconnection
•Remaining life is for the generation, transmission may differ
•Numbers are from the end of 2018 and may change as pieces depreciate or new capital is added
•Colstrip modeling will use a 2025 for Washington and 2027 for Idaho
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 505 of 1057
2020 Electric IRP
Final Resource Need Assessment
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
August 6, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 506 of 1057
Agenda
•2020 IRP Load & Resource Balance
•Avista’s Clean Energy Goals
•Energy Independence Act Renewable
Requirement Forecast
•Clean Energy Transformation Act Forecast
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 507 of 1057
Load & Resource Methodology Review
•Sum resource capabilities against loads
•Resource plans are subject to 5% LOLP analysis –
determines planning margins
•Capacity
–Planning Margin (14% Winter, 7% Summer)
–Operating Reserves and Regulation (~8%)
–Reduced by planned outages for maintenance
–Plant 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
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 508 of 1057
One Hour Peak Load & Resource Position
4
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 509 of 1057
18-Hour Sustained Peak L&R
5
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 510 of 1057
1,000
1,200
1,400
1,600
1,800
2,000
2,200
-20 0 20 40 60 80 100
Me
g
a
w
a
t
t
s
Average Daily Temperature (Degree's Fehrenheit)
Load Variability (Temperature Variation)
Winter
Plan: 10
Degrees Summer
Plan: 80
Degrees
Winter Summer
90th Percentile 1,881 1,710
Mean 1,718 1,627
10th Percentile 1,565 1,542
90th -Mean 163 83
241 MW Planning
Margin @ 14%114 MW Planning
Margin @ 7%
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 511 of 1057
Energy Load & Resource Position
7
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 512 of 1057
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
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 513 of 1057
Avista Corporate Clean Energy Goals
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 514 of 1057
Washington State Clean Energy Goals
•Energy Independence Act or Initiative 937
–15% of Washington retail load after 2020
–Qualifying resources less any forward sales obligations
–Banking provisions mitigate year-to-year variation
–Addition of qualifying BPA and Wanapum, which are not included
in the chart. Will update when amounts are known.
•Clean Energy Transformation Act
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 515 of 1057
Washington Energy Independence Act
11
-
20
40
60
80
100
120
140
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
Wind Solar Wood EIA Goal
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 516 of 1057
Avista’s Washington CETA Goals
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 517 of 1057
Attendees: TAC 4, Tuesday, August 6, 2019 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Thomas Dempsey, Avista; Steve Johnson, Washington UTC; Brian
Parker, 350.org; Barry Kathrens, 350.org; Gerry Snow, Pacific Energy Research Associates; Michael Eldred, Idaho Public Utilities Commission; Terrence Browne, Avista; Greg Rahn, Avista; Ryan Ericksen, Avista; Mike Dillon, Avista; Ryan Finesilver, Avista; Jared Akins, Avista; Tom Pardee, Avista; Garrett Brown, Avista; Jaime Majure,
Avista; Clint Kalich, Avista; Scott Kinney, Avista; Jennifer Snyder, Washington Utilities
and Transportation Commission; Chris Zentz, National Grid; Kevin Davis, Inland Empire Paper; John Barber, Rockwood Retirement Communities; Dave Van Hersett, Residential Customer; Steve Wenke, Avista; Dennis Cakert, National Hydropower Association; Jose Phillips Rangel, Avista; Annie Gannon, Avista; and James Gall,
Avista.
Phone Participants:
Kevin Keyt, Idaho Public Utilities Commission; Idaho Office of Energy; Shelby Herber,
Idaho Conservation League; Tina Jayaweera, Northwest Power and Conservation
Council ; Mike Starrett, Northwest Power and Conservation Council; Fred Heutte,
Northwest Energy Coalition, and others who did not identify themselves.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses are in italics, and
significant points raised by presenters that are not shown on the slides are also
included.

Introductions and TAC 3 Recap and Washington SB 5116 and IRP Updates, John
Lyons
Steve Johnson: Is this the specific avoided cost for peak summer hours. Yes, avoided
cost of energy and capacity or summer; i.e., $1 per kWh month.
Clint Kalich: PRiSM technology allows us to calculate capacity values.
Steve Johnson: As we dispatch gas less, per unit increases so capacity value becomes
more. Attract more developers to the Northwest by showing them a price.
James Gall: Duration problem, 6-hour vs. 2-hour peak contribution.
Steve Johnson: Hours and frequency.
Clint Kalich: Disincent new energy and incent capacity.
Jennifer Snyder: Really like to see an actual target in Demand Response (DR) in this
IRP. James Gall: We expect this, but things that provide energy and capacity might
push DR out.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 518 of 1057
Energy and Peak Load Forecast Update, Grant Forsyth
Dave Van Hersett: Is slide #6 a percentage scale. Yes, now 8-9% above where we were
in 2007.
Steve Johnson: Does the model capture recession events? Not really, timing is difficult
and we haven’t really beat the business cycle.
Steve Johnson: Load forecasts have consistently been high. Action Item to keep in mind
is to be responsive to economic downturns. Not saying that you need to change models,
but consider the impact of these actions. I now run the forecast twice a year to more
quickly see changes in the forecast.
Grant Forsyth: Slide #7 population growth is a proxy for customer growth. About 2011,
the natural birth/death rate with very little in-migration.
Dave Van Hersett: Where are they coming from? Mix of everywhere, but a lot from
California based on driver’s license surrenders. Also relocating business operations
from the west side of the state.
Greg Rahn: Does the blue bar [slide 7] imply more exposure to recessions. Yes.
Linda Gervais: How has DSM influenced summer/winter peak? Still winter peaking, but
summer peak is growing at a faster rate than winter because of a better economy,
warmer summers and adopting more air conditioning.
Steve Johnson: Data going back to 1890, is there some other explanation for the last 20
years? May inform gas dispatch for the four-year plan and reshape hydro. There are not
very good models for local temperature change. Imperfectly calculated risk.
Clint Kalich: Can the data even be loaded from those models? Are other utilities looking
at shorter periods [of weather data]? It is hard to explain the oscillation of weather using
historic data.
James Gall: There is a risk if we exclude past peaks from shorter time periods. Bigger
risk of missing a peak. Energy – short. Peak – capacity.
John Barber: New climate studies. Are they ready? Starting to “downscale” global
models, but no commonly accepted methodology to do this exists. Which study do you
choose? Which downscaling method to you use? We don’t know, but the University of
Washington and Oregon State University are working on this issue. We went to 20-year
average, but I’m still not comfortable enough with them yet to shift away from the
moving average.
Grant Forsyth: Slide 11 – actual, not weather normalized pre 2019.
James Gall: We plan for the tail events to maintain adequate supply.
Gerry Snow: Winter tail? Summer looks more like a bell curve. Long tail at low
temperatures, this is what we are worried about for capacity.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 519 of 1057
James Gall: There is greater winter than summer variation.
Steve Johnson: There is a smaller area under the curve, so there may be fewer cold
events. NASA analysis for the 1950-1981 period for the temperature difference from
average, shows a bigger summer than a winter shift.
Steve Johnson: With EVs [electric vehicles], do you think you need more resources in
the next five years or later? No, our needs from resource retirements and contracts
ending are a greater impact than EVs.
Slide #15 – medium term forecast is now done twice yearly.
John Barber: Southerly parts of the country – looking at fleeing to places like here. May
be looking at climate refugees. Climate Council is looking at how climate and water is
changing, but there is still a substantial investment in these areas so what will be spent
on mitigation, so hard to work into the forecast.
Barry Kathrens: Won’t these impact us too? May impact other areas. They would be
impacted, but not as much. A lot of coastal regions are going to be going somewhere.
Slide 19 – PV is rooftop solar.
John Barber (Slide 19): About a 2% penetration rate? A generous forecast, but not
unreasonable.
Slide 20: About 13% electric vehicle penetration rate for residential.
Gerry Snow: Spokane transit may be the first big commercial EV customer.
Steve Johnson: Graph timing of EV. Tough to calculate because small changes up front
make huge changes later.
Steve Johnson (Slide 21): Don’t the wealthy buy most of the cars anyways? Yes, but we
also need a robust used market of EVs. Besides income, density is another predictor,
probably because of range issues. This curtails regional uptake of EVs.
Slide 22: Could have significant transportation emission savings. Still a net benefit per
year with the switch to EVs.
Steve Johnson (Slide 26): I’m confused, difference in UPC winter vs. summer. My
guess is a disproportional effect on UPC on summer because of heating.
Natural slowing of gas because of penetration, but not a specific cause.
Jim Le Tellier: Must be going to different meetings, because that is the next big thing for
environmental groups.
James Gall: It’s a very large cost for a small benefit with the extra cost of wiring.
Jim Le Tellier: Not an argument, just observing.
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Schedule 1a, Page 520 of 1057
Steve Johnson: Price of gas falls, but price of electricity is going up.
Gerry Snow: It might be cheaper to decarbonize gas, rather than getting rid of it.
Steve Johnson: If the cost per unit is high, plus low greenhouse gas benefits, there may
be a lot of pushback.
Steve Johnson: Strong enough population growth is overcoming no load growth.
Clint Kalich: Red bump on slide #25 (2023 to 2024), need to check why it is increasing.
Steve Johnson: Would like to leave feeling like he [Grant] can stand by the forecast. Big
forecasters still fundamentally different now. This is the best guess I’ve got now. All
sorts of weird stuff can happen.
Clint Kalich: We have low load growth and no immediate needs.
Steve Johnson: Lot of end use incentives. People want the service, not the thing. They
want cold milk, not electricity. Would like to see more focus on the service. More DSM
deployed and recognized. Tech geek out on the conservation side.
Jenifer Snyder: (Slide 26) 2020-2021 jump. Intermediate term probably enough
correction process going from further out. Pushes more to the long term. Price elasticity
assumption – price not statistically significant anymore using academic studies. Longer
term – no longer assume real price is constant, now increasing.
Steve Johnson: Colstrip remediation costs also impacting
Dave Van Hersett: Small in comparison.
Steve Johnson: Can be significant. We’ll see.
Substituting rising price for conservation in the long run.
Steve Johnson (Slide 29): Conservation adopted this year or actual effects. This is the
amount DSM said they got per month.
Jennifer Snyder: Savings in that year. Grant cumulatively builds them in. Persistence?
Assumes going forward in time.
Dave Van Hersett (slide 29): Is the 12% per year of 1%?
James Gall: More like 1% per year, the average of those.
Slide 30: Preliminary about 60% of black line.
Tina Jayaweera: How do codes and standards fit in?
James Gall: Transfers from programs to standards. Grant builds in a trend, pushed
forward, but there is no specific variable to change.
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Schedule 1a, Page 521 of 1057
Tina Jayaweera: About 2012, standards really increased. Hard because of the timing.
We have some estimates that can be shared. Yes, please. Masood has these.

Natural Gas Price Forecast, Tom Pardee
Gerry Snow (Slide 3): Is Jackson Prairie a geologic formation. Yes, an old aquifer.
There are no salt domes available regionally.
John Barber: Dth? Dekatherm, million BTU or 10 therms.
Fred Huette (slide 7): Numbers may be off a bit: 4.5 Bcf British Columbia and 10.5 Bcf
Alberta. The slide actually came from the Canadian government. We have all learned
more about gas north of the boarder.
Clint Kalich: Do you have statistics on the relative amounts of LNG vs. coal to China?
No.
Fred Huette: If LNG is at 3.5 Bcf, any sense of price impacts? Yes, in a few slides.
Basically, their own pipeline, so will take away capacity potentially, but new filled so it
lessens the impact to the AECO trading hub.
Slide #11: 90 Bcf yesterday. About half to electric generation. 120 Bcf /day by 2050.
Slide #12: “Proved” reserves – fairly economic and could be extracted if need be.
Fred Huette: Not sure I would agree with reserves. Definitely a lot less, maybe better if
we communicate offline about this. On EIA as well, about 400 Tcf, about 360 Tcf last
update.
Steve Johnson: What if solar gets really cheap, cost per mmBtu for gas products?
Depends by area. What does the curve look like? Actually negative in the Permian
where they are drilling for oil and natural gas is a byproduct. Marcellus is more of a dry
gas with a higher marginal cost to extract.
Jim Le Tellier: Could be a lot higher. Like solar curtailment, got to get rid of it. Yes.
What is the long term production cost if they have to pay back Wall Street? Typically, no
free cash flow. Typically a hockey stick with high initial production in the first year,
followed by less production, so they have to keep drilling. Now five days on average. Oil
projects are long-term and large capital, not so much with [natural] gas only producers.
Clint Kalich: Social policy might be more of a driver than investment.
Fred Huette: I have a somewhat different view. 80 years based on resources, not
proved reserves. 464 Tcf, about 30 Tcf consumption. We should probably get together
on this offline.
Grant Forsyth (Slide 15): Gas-fired generation in Canada? Or east?
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 522 of 1057
Steve Johnson: What is driving increasing prices?
Fred Huette: What is your opinion or view of the differential between AECO and Henry
Hub? Will it persist or is it temporary? Never expect it to persist, but producers are trying
to think about curtailing production to get closer to Henry Hub prices. Not sure why they
can’t, will seek normal returns.
Clint Kalich: Oil is a bigger driver.
Steve Johnson: 2011 with falling prices, suppliers still want to do shorter contracts
instead of long term. Is it because of fracked gas? A lot of them do hedge 3 to 5 years,
or less, to lock in margin.
Barry Kathrens: Can’t help thinking it might be a little low at 1 – 3%.
Gerry Snow: Is this based on CO2 equivalent? Yes, so different if flaring or leaking with
a 28 times multiplier for leaking.
Fred Huette: Interested again offline. It’s a difficult question with a lot of information
coming in. GWP [global warming potential] for 100 years is 33 or 36 times CO2, 20-year
is about 85. Atmospheric is 10 – 15 years, CO2 is much longer.
Steve Johnson: Has Avista examined the methodologies? No, haven’t seen if
methodology is available. It is set by the Canadian government and there is a tendency
towards less reporting.
Clint Kalich: So now we need to second guess federal studies?
Steve Johnson: The key is if you buy a product, you need to know it. Get a sense of risk
if they are off. It may be hard to calculate and may not be very willing to report it. Not
asking you to reinvent, but do you put a brand on it. Informing customers of what
product they are getting. Could just say it in the IRP. If the methodology is self-reporting
– it’s a red flag. If spot measurement, that’s better. Risk of non-cost effective
conservation.
Jim Le Tellier: How did they build that [CO2 reports]?
Clint Kalich: What do we do?
Tom Pardee: We have the date and documents. Should have a description of how they
developed the numbers.
Fred Huette: I know a fair bit about this issue. Five years ago, it was based on a lot of
engineering data. EDF managed a large research project on this issue and others, so
more data is folding into it and the numbers are getting better. Flaring is not a big issue
in the northwest, but probably a little bit. Probably Bakken and Permian oil dominated by
less gas infrastructure. Very little of this is coming to the Pacific Northwest. Data is
reported to the states and to the feds. The industry has an incentive to reduce flaring,
but the low prices don’t incent it.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 523 of 1057
Fred Huette (Slide 21): Able to cover almost all times in non-firm in the past when there
was spare capacity, now no firm gas is left. Jackson Prairie rights are on the LDC [local
distribution company] side, so there is no interaction with it and generation.
Gerry Snow: Have you investigated into renewables to hydrogen? Yes, we also looked
at hydrogen at the same time. Renewable about $40/Dth to hydrogen to a fuel cell in
this IRP. It’s very good for long-term storage. There is also methanization, but at a
higher cost.
Fred Huette: Unsure with pumped storage. Very big and limited places.

Electric Price Forecast, James Gall
Dave Van Hersett (Slide 7): At night, use something else than solar. Every day’s price
and standard deviation of price (volatility).
Slide 7: Implied market heat rate equation.
Steve Johnson: What is causing higher 2018-2019 prices? Start up for fewer hours per
day, etc.
Fred Huette: In California last year, they are all out of range. Scarcity pricing for Aliso
Canyon storage and pipeline issues. Persistently high prices. Will these continue? Much
work is being done to calm down prices as things are fixed.
Fred Huette: Kevin Harris at Columbia Grid has studied the startup issue.
Fred Huette: High hydro, low gas burn, but fairly stable online.
Fred Huette: Will see higher emissions this year. Pretty stable market.
Clint Kalich (Slide 16): How do you reconcile resource need with the Council?
Jennifer Snyder (Slide 17): Does load growth include conservation? Yes, low level of
conservation assumed by the consultant.
Thomas Dempsey: What is the 2045 percentage clean? Over 80%, Northwest is 110%.
Western Interconnect excludes Canada and Mexico. Assumes Colstrip out of
Washington by 2025, but we assume there will likely be some generation out of Colstrip
still for other areas.
Fred Huette (Slide 17) Aurora inputs?
1. Future resource cost projections from a consultant, can’t tell you who, plus
incentives; and the vendor of Aurora. NREL annual technology report just
released 2019 update.
2. Solar, wind, storage. We can send out the cost assumptions. Solar plus
storage.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 524 of 1057
3. Carbon pricing in model for future and existing resources. Washington uses
the social cost of carbon. Other states/provinces include their own
requirements – California, British Columbia, and Alberta.
4. Hydro modeling in Aurora is good, but not great. How do we modify it? 80-
year energy input plus how flexible (Power Council factors) for hydro.
Fred Huette (Slide 18): Are you doing anything to shock or perturb gas prices for
unexpected conditions? Yes, different hydro, load, gas prices, etc. for each of the 500
runs.
Dave Van Hersett: Do rising gas prices raise electric prices? Market prices are relatively
flat in real terms.
Fred Huette: What is the stochastic range? Using randomized draws.
Fred Huette (Slide 20): High load hours with 2026 being higher makes total sense. I’ve
actually studied the market in California. It is lower in the day than at night. The theory is
that gas plants are bidding in the evening and recovering their costs then. May not shift
total market revenue. Solar plus storage first reduces curtailment and then helps with
the ramp.
Steve Johnson: 8 to 16-hour is not relevant anymore.
Mike Dillon: Lot of seasonality, summer 20-21 hours for EIM buyers spike and it spikes
aggressively. The value of flexibility and instant capacity is more.
Clint Kalich (Slide 22): Gas has collapsed showing most of this.
Steve Johnson: Price spike volatility in gas prices. Smaller gas exposure diminishes
impact. More impactful for winter than summer.
Jim Le Tellier: This doesn’t agree with the articles in the paper making statements about
general shift of renewables blowing out bills.
Steve Johnson: The differential has collapsed, but capacity supply will explode in the
other direction.
Clint Kalich: So suppose we now have 5 cents for energy and 2 cents for capacity, we
will have 2 cents for energy and 5 cents for capacity in the future.
Steve Johnson (Slide 25): Why is March so high? Probably because of the ramp spiking
prices. Need to look at this. It is a penalty to turn back on. Not as much with higher
loads.
Fred Huette: A few slides ago, 2030/35/40. It is really great to see shifting prices and
resource availability.
John Barber (Sldie 31) EUE? Average load unserved.
Clint Kalich: Energy that would have to be curtailed in the market.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 525 of 1057
Clint Kalich: PV [present value] of portfolios to run. Didn’t have to do the math or a
levelized cost, wholesale prices are down and retail price up.
Fred Huette: How did you apply the Social Cost of Carbon? Applied the Social Cost of
Carbon in dispatch for the entire Western Interconnect generation fleet.
Phone: Is the 2020 and 2035 levelized cost for deterministic with California and British
Columbia. Yes, in Expected Case. Social Cost of Carbon case overrides.

Existing Resource Overview, John Lyons
Gerry Snow: Limestone wet scrubbers? Yes.
Steve Johnson: There is a lot of water you can’t get rid of if the plant is off. The majority
of the water leaves through the stack and evaporation. The remedy and closure plan
gets to a net zero point about 30 years out on the current model.
Jim Le Tellier: Sometimes the preliminary estimates are off. Article in the Billings
Gazette was $700 million of cleanup costs [for contaminated water]. That number is for
all four units added together.
Gerry Snow: If you stop bringing in more water? About 470 million gallons on site now, it
was about 700 million gallons.
Fred Huette: What about the new [coal] contract? It will be an all-party contract.
Jennifer Snyder: Is Coyote Springs 2 getting a major redesign? GSU [generation step
up] transformer is the problem. Looking at breaking into individual phases outside of the
IRP, but using the IRP to help evaluate because of losses to winter capacity. Already
submitted a business case, but haven’t made a decision yet.

Final Resource Needs Assessment, John Lyons
Fred Huette: Tenth percentile for hydro? We look at the tenth percentile, enough in nine
out of 10 years. Others use critical water. One consistent month – 1937 was a bad
winter, but an average summer.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 526 of 1057
2019 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Tuesday, October 15, 2019 Conference Room 130

Topic Time Staff
Introductions, Updates and TAC 4 Recap 9:30 Lyons

Energy Imbalance Market Update 10:00 Kinney Break 11:00 Storage and Ancillary Service Analysis 11:15 Shane
Lunch 12:00

Preliminary Preferred Resource Strategy 1:00 Gall
Break 2:00 Preliminary Portfolio Scenario Results 2:15 Gall Adjourn 3:30

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 527 of 1057
2020 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
October 15, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 528 of 1057
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•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
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 529 of 1057
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 in all or some of the process
•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 studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 was the latest to be able to complete studies in time for
publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 530 of 1057
TAC #4 Recap –August 6, 2019
•Introductions and TAC 3 Recap, Lyons
•Washington SB 5116 and IRP Updates, Lyons
•Energy and Peak Load Forecast Update, Forsyth
•Natural Gas Price Forecast, Pardee
•Electric Price Forecast, Gall
•Existing Resource Overview, Lyons
•Final Resource Needs Assessment, Lyons
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-company/integrated-
resource-planning
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 531 of 1057
Today’s Agenda
9:30 –Introductions and TAC 4 Recap, Lyons
10:00 –Energy Imbalance Market Update, Kinney
11:00 – Break
11:15 –Storage and Ancillary Service Analysis, Shane
Noon –Lunch
1:00 –Preliminary Preferred Resource Strategy, Gall
2:00 – Break
2:15 –Preliminary Portfolio Scenario Results, Gall
3:30 –Adjourn
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 532 of 1057
Future TAC Topics
•TAC 6: Tuesday, November 19, 2019
–Review of final PRS
–Market scenario results (continued)
–Final Portfolio scenario results
–Carbon cost abatement supply curves
–2020 IRP Action Items
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 533 of 1057
2020 Electric IRP
Energy Imbalance Market Update
Scott Kinney, Director of Power Supply
Fifth Technical Advisory Committee Meeting
October 15, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 534 of 1057
Discussion
•Market Operations Today
–NW bilateral market
–California Independent System Operator (CAISO) market
•Western Energy Imbalance Market (EIM)
–How the EIM works
–Current participants
•Avista’s Decision to join the EIM
–Drivers
–Costs and benefits
•Project Status
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 535 of 1057
Organized Electric Markets
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 536 of 1057
NW Bilateral Market
•No organized market
•Utilities operate individually
–Buy/sell with counterparties or through electronic clearing house
•Monthly, day ahead and hourly
–Utilities hold extra resources to meet forecast error
•Can’t take advantage of regional load/resource diversity
–Must meet all NERC compliance requirements
–Perform transmission planning
–Facilitate transmission tariff and sales
•Less efficient
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 537 of 1057
The CAISO Market
•The California Independent System Operator (CAISO)
runs a full organized energy market in California
•Based in Folsom, CA, operational since 1998
•Utilities maintain ownership of generation and
transmission assets
•CAISO ensures sufficient resources to meet CA load
–Balancing Authority for members
–Day ahead dispatch plan
–Real-time resource dispatch
•Conducts long-term transmission planning
•Facilitates transmission tariff and sales
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 538 of 1057
What is the Western Energy Imbalance
Market?
•Operational since 2014 –CAISO and PacifiCorp
•The EIM is an economic based 5 minute in-hour regional
resource dispatch program
–Allows participants to lower energy costs
•Dispatch less expensive resources to meet in-hour load
obligations
•Increase revenue through the bidding of excess energy
•Monetize resources traditionally held for regulating reserves
–The EIM dispatches the most economic resource across its entire
market footprint every 5 minutes based on bid prices to balance
in-hour load and generation
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 539 of 1057
Why EIM?
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 540 of 1057
How the EIM Works
•Participants must show they can meet load obligations prior to the
operating hour, no leaning on the market
•Participants voluntarily submit resource availability, min/max, ramp
rates and price curves
•CAISO runs a security constraint (i.e. transmission) economic
dispatch every 5 minutes to obtain the optimal economic and reliable
resource solution for the EIM footprint
•Transmission congestion leads to price differentials
•CAISO sends a 5 minute dispatch request to selected resources to
meet overall footprint load obligation
•Generators and load are assigned a locational marginal price based
on the economic dispatch and transmission congestion
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 541 of 1057
EIM Supply Transfers Benefit Both Areas
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 542 of 1057
EIM Supply Transfers Benefit Both Areas
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 543 of 1057
http://www.caiso.com/TodaysOutlook/Pages/prices.aspx
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 544 of 1057
EIM Participants
•Members -CAISO, PAC, NVE,
PSE, APS, PGE, IPC,
Powerex, BANC (SMUD)
•Committed
–2020 –SCL, SRP
–2021 –PNM, NWE, LADWP, TID
–2022 –Avista, TEC, Tacoma, BPA
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 545 of 1057
EIM Gross Benefits
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 546 of 1057
Market Monitoring Phase 2015-2018
•Limited needs and risks
–Small renewable penetration
–Economics not compelling
–Other large technology projects
•Monitor market development
–Engage in public processes and meetings
•EIM Entity outreach and site visits
•CAISO Scheduling Coordinator certification
–June 2016
•Infrastructure evaluation
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 547 of 1057
Avista Decision Drivers and Risks
•In-hour market liquidity risks
–2018 summer issues
–NWE joining in 2021, BPA planning to join in 2022
•Renewable energy integration
–Rattlesnake Wind contract -145 MWs end of 2020
–Transmission interconnection queue >1000MW
–Avista’s clean energy goals
–State policies and regulations
•WA Clean Energy Bill
•WA PURPA changes
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 548 of 1057
Avista Decision Drivers and Risks cont.
•Economics
–Customer benefits
–Risks of not joining
•Reduction in current optimization opportunities
•Higher resource dispatch costs
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 549 of 1057
Avista EIM Costs and Benefits
•Estimated EIM costs
–$21 –26 M start-up
–$3.5 –4.0 M on-going
•Anticipate 12+ new FTE for on-going support
•Estimated annual benefits
–Full range $ 2 –12 M
–Expected range $3.5 -9.2 M
–Base $5.8 M
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 550 of 1057
Utility EIM Cost/Benefit Comparison ($M)
18
PAC NVE PSE APS PGE IPC AVA
Actual Costs 21.0 11.5+22.0 16.0 22.0 12.0+21.5
Studied
Benefits 35.1 10.8 14.1 4.9 3.5 4.1 5.8
2018 Actual
Benefits 61.7 25.6 13.7 45.3 27.6 26.9 ?
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 551 of 1057
Project Status
•Officer approval on April 15 to join EIM
–Go-live April 1, 2022
•CAISO Contract
–Signed Integration Agreement on April 25
•System Integrator –Utilicast
•Current efforts
–Upgrade/replace meters and generation controls
–Expand telecomm networks
–Request For Proposals for EIM applications
•Issued Outage Management RFP on August 13
•Issued Bid to Bill RFP on September 17
–ADSS enhancements
–Staffing plan and training
19
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 552 of 1057
20
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 553 of 1057
2020 Electric IRP
Storage and Ancillary Services Analysis
Xin Shane, Senior Power Supply Analyst
Fifth Technical Advisory Committee Meeting
October 15, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 554 of 1057
Challenges of Energy Storage Valuation
Source: Northwest Power and Conservation Council white paper on the
value of energy storage to the future power system
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 555 of 1057
Value Stream Definition
•Frequency Response: Automatic generator response to grid frequency
excursions
•Contingency Reserves: Reserves available for grid emergencies
•Regulation: Instant response to system load fluctuations
•Load Following: Follows system load fluctuations
•Arbitrage: Store energy when price is low and discharge when price is high
•Avoided Curtailment: Storing energy during times of oversupply to avoid
generation curtailment
•Peaking Capacity: Ensure sufficient capacity to meet forecast peak demand
•Energy: Optimizes energy timing to meet load
•T&D Deferral: Reduce loading on transmission paths and loading on
distribution circuits during peak demand periods
•Volt/Var: Provide reactive power within the distribution system to maintain
nominal grid voltage and enhance the power carrying capability of transmission
system
•Outage Mitigation: Help with unplanned outages with back-up power for
reliability and resilience
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 556 of 1057
Avista Decision Support System
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 557 of 1057
Battery Study Overview
•Turner Energy Storage Project –1 MW, 3.7 MWh
vanadium redox flow battery
•Partnered with PNNL to study operational use cases for
the Clean Energy Funds grant.
•Study focuses on regulation and reserves
5
Turner Energy Storage Project, Pullman, WA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 558 of 1057
Battery Operating Characteristics
Charge
Discharge
State of Charge (SOC) –An expression of the present battery capacity as a
percentage of maximum capacity.
Power –instantaneous kilowatts.6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 559 of 1057
Modeling Overview
Targeted Battery Rating
•Max Capacity – 1.0 MW
•Max Storage –3.7 MWh
Applied Battery in Model
•Max Capacity – 10 MW
•Max Storage –37 MWh
-$10.0
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
$70.0
(12.0)
(7.0)
(2.0)
3.0
8.0
1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97
10
1
10
5
10
9
11
3
11
7
12
1
12
5
12
9
13
3
13
7
14
1
14
5
14
9
15
3
15
7
16
1
16
5
Hourly Battery Discharge
Net Discharge MCMktPrice
MW
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 560 of 1057
Price Volatility Impact
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 561 of 1057
Benefit Evaluation
Scenario Power Price Gas Price Benefits
1st Run Forecasted Monthly Forward $5.00/kW-yr
2nd Run Year 2016 Power
Index Price
Monthly Forward $6.63/kW-yr
3rd Run Year 2014 Power
Index Price
Year 2014 Daily $36.32/kW-yr
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 562 of 1057
Pumped Hydro Study
Operating Characteristics
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 563 of 1057
Pumped Hydro Scenarios and Results
System Configuration Target
Project
Scaling
Incremental Value
($)
Incremental
Value
($/kw-yr)
Avista System 3 by 400 MW 100%$19,412,500 $ 16.18
Avista System 3 by 100 MW 25%$ 6,772,468 $ 22.57
Avista System 3 by 40 MW 10%$ 3,057,399 $ 25.48
Avista System 3 by 20 MW 5%$ 1,598,433 $ 26.64
Hydro Reduction 3 by 40 MW 10%$ 4,730,827 $ 39.42
Noxon 1 120 Cabinet 1 65 Long Lake 1 22 Little Fall 1 8.5
Noxon 2 120 Cabinet 2 78 Long Lake 2 22 Little Fall 2 8.5
Noxon 3 120 Cabinet 3 79 Long Lake 3 22 Little Fall 3 8.5
Noxon 4 120 Cabinet 4 68 Long Lake 4 22 Little Fall 4 8.5
Noxon 5 135
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 564 of 1057
Pumped Hydro Incremental Value Results
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 565 of 1057
Future Energy Storage Analyses
•Re-evaluate energy storage options in a shorter term
energy market
•Analyze different energy storage technologies
•Updated pumped storage hydropower technologies
•Study with different levels of wind and solar penetration
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 566 of 1057
2020 Electric Integrated Resource Plan
DRAFT “Preferred” Resource Strategy
James Gall, IRP Manager
Fifth Technical Advisory Committee Meeting
October 15, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 567 of 1057
DRAFT ONLY
What Are Avista’s Physical Resource
Needs?
Main focus: Winter Peak (e.g. cold week in January)
Avista is also short in summer and on an annual average basis
beginning in 2027
-
500
1,000
1,500
2,000
2,500
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
Me
g
a
w
a
t
t
s
Available Resources Net Requirement
Gap
2026: 14 MW
2027: 302 MW
2030: 325 MW
2035: 495 MW
2040: 537 MW
Key Losses:
Colstrip: 2025*
Lancaster: 2026
Mid-C: 2030
Northeast: 2035
2 * Colstrip is assumed offline at the end of 2025 for planning purposes only. Avista’s ultimate decisions regarding
Colstrip are still to be determined.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 568 of 1057
DRAFT ONLY
Washington SB5116 Clean Requirements
2026: Colstrip can no longer serve Washington Load
2030: 80% energy delivered over a four-year period is clean and 20% can be RECs
2045: Goal to be 100% clean (will require new technology to stay under cost cap)
Gap
2030: 54 aMW
2035: 130 aMW
2040: 182 aMW
2045: 353 aMW
Key Losses:
Mid-C: 2030
Lind: 2039
Rattlesnake: 2040
Palouse: 2043
Assumes: Idaho customers sell offsets to Washington Customers
0
100
200
300
400
500
600
700
800
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
Washington Existing Qualifying Resources
Idaho Available Hydro RECs
Washington Net Requirement
Washington Retail Sales
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 569 of 1057
DRAFT ONLY
Avista’s Clean Electricity Goal
0
200
400
600
800
1,000
1,200
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 Existing Resources System Retail Sales (aMW)
2027: 100% net clean portfolio wide (cost effective considerations)
2045: 100% clean (cost effective considerations and technology)
Gap
2027: 339 aMW
2030: 360 aMW
2035: 426 aMW
2040: 448 aMW
2045: 562 aMW
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 570 of 1057
Resource Options
Clean
•Wind (WA/OR/MT)
•Solar (WA/ID/OR)
•Biomass (WA/ID)
•Hydro Upgrades (MS, LL)
•Hydro (Mid-C)
•Hydro (BPA)
•Geothermal
•Nuclear
•Energy Efficiency
•Demand Response
Other
•Natural Gas CT
•Natural Gas CCCT
•Storage
–Pumped hydro
–Lithium-ion batteries
–Liquid air
–Hydrogen
–Flow batteries
•Regional Transmission
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 571 of 1057
DRAFT ONLY
Preferred Resource Strategy Decision
Process
•Uses Mixed Integer Program (MIP) to find least cost solution
meeting capacity, energy, and renewable constraints for the system
between 2021 and 2045.
•Only known model with full co-optimization of energy efficiency and
demand response with supply side resources.
–Capable of co-optimization of T&D system with power system
•Accounts for societal preference Washington state planning criteria
–(Social Cost of Carbon, 10% cost advantage from energy efficiency,
upstream pipeline emissions, etc.)
•Non-modeled utility revenue requirements assumes an increase of
two percent per year.
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 572 of 1057
DRAFT ONLY
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Energy Efficiency Results
45% increase
Note: excludes T&D losses7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 573 of 1057
DRAFT ONLY
Where is the Cost Effective Energy
Efficiency Savings?
Residential
40%
Commercial
49%
Industrial
11%
2040 Customer Class Savings
0.7
1.2
1.4
3.4
4.0
4.3
5.2
5.2
5.4
5.8
7.3
11.2
14.0
30.0
44.6
0 10 20 30 40 50
Office Equipment
Process
Miscellaneous
Food Preparation
Cooling
Heating
Electronics
Refrigeration
Motors
Appliances
Ventilation
Space Heating
Exterior Lighting
Water Heating
Interior Lighting
Average Megawatts
2040 Cumulative Savings
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 574 of 1057
DRAFT ONLY
Washington Biennial EIA Energy
Efficiency Goal (2021/22)
9
Biennial Conservation Approved
Target (MWh)
Based on
2020 IRP
Based on
2017 IRP
CPA Pro-Rata Share 72,338 73,636
Behavioral Program Savings N/A 15,386
Distribution and Street Light Efficiency 504 749
EIA Target 72,842 89,771
Decoupling Threshold 3,642 4,489
Total Utility Conservation Goal 76,484 94,260
Excluded Programs (NEEA)-14,016 -9,986
Utility Specific Conservation Goal 62,468 84,274
Decoupling Threshold -3,642 -4,489
EIA Penalty Threshold 58,826 79,785
73,636 72,338
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2017 IRP 2020 IRP
MW
h
Biennial Pro-Rate Share (10 yr)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 575 of 1057
DRAFT ONLY
$0
$20
$40
$60
$80
$100
$120
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
k
W
-yr
Capacity Value
Energy Efficiency Avoided Cost
Energy, $26.44
Clean Premium,
$16.35
Losses, $2.61
Preference, $4.54
$0
$10
$20
$30
$40
$50
$60
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
M
W
h
Energy Value
$49.95/MWh $101.27/kW-yr
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 576 of 1057
DRAFT ONLY
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
- 20 40 60 80 100 120
$
p
e
r

k
W
-yr
Megawatts
Demand Response
Summer Programs Evaluated
•Central A/C
•Smart Thermostats-Cooling
•Thermal Energy Storage
11
25 MW Load Control is also included, but not shown as its prices would likely be negotiated
Cost Effective Start Dates Shown in Red
2026: Variable Peak Pricing2029: Time of Use
2029: Industrial Load Control
2030: Smart Thermostats
2043: Ancillary Services (TBD)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 577 of 1057
DRAFT ONLY
2022-2025 Generation Action Plan
•2022-2023 RFP
–Early acquisition to take advantage of tax credits
–Anticipate 300 MW Wind PPA (84 aMW)
•100 MW in MT and 200 MW in NW
•locations depend on transmission availability
–Solar could replace wind depending on pricing and future price shape forecasts
–Potential for additional resource acquisitions in support of Avista’s clean
electricity goal subject to reliability and affordability considerations.
•2024: Kettle Falls Upgrade
–Incrementally increase Kettle Falls generating capability by installing larger sized
equipment as part of modernization
•2025: 222 MW, Colstrip removed
–Per CETA, Colstrip will not serve Washington loads after 12/31/2025
–The plants future for Idaho customers or wholesale transactions is yet to be
determined
12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 578 of 1057
DRAFT ONLY
2026-2030 Generation Action Plan
•2026: 150 MW, Pumped Hydro
–Assumes low cost, long duration pumped hydro solution is available.
–If resource is not available or price exceeds cost effectiveness tests, siting a
similar sized NG peaker is the next least cost option.
–Sizing will depend on reliability requirements of future power supply system.
•2026: 24 MW, Rathdrum Upgrade
–Increases each unit by 6 MW using a supplemental compression technology or
alternative technology.
•2026: Lancaster PPA expires in October
•2027: 200 MW, MT Wind
–Utilizes Colstrip transmission,
–if not available additional NG and renewables are required.
•2027: 8 MW, Post Falls Upgrade
–Increase generating capability as part of modernization project to maintain FERC
licensing requirements.
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 579 of 1057
DRAFT ONLY
2031-2040 Generation Action Plan
•2031: Attempt to renew Mid-C PPA contracts
•2033: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2035: Northeast CT retires
•2035: 68 MW Long Lake 2nd Powerhouse
–Seek certification as an eligible resource
•either as 2nd powerhouse and/or reconfiguration of single new powerhouse.
–Begin licensing process
–Optimize the site for cost, capacity, and environmental concerns
–Earlier on-line date may be possible
–NG Peaker and renewable resource would be alternative to this project
•2036: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2038: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2039: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 580 of 1057
DRAFT ONLY
2040-45 Generation Action Plan
•2041: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2042-2045: 300 MW Wind PPA Replacement
–Existing PPAs begin to expire
–Repowering is likely necessary
•2043: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2042-2045: 250 MW x 4 hour, Lithium-ion (or lowest cost alternative)
•2044: 50 MW, solar w/ 50 MW x 4 hour storage
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 581 of 1057
DRAFT ONLY
DRAFT Preferred Resource Strategy
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 85 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2033: 25 MW x 16 hr Liquid Air Storage
2035: 55 MW, Northeast CT retires
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 25 MW x 16 hr, Liquid Air Storage
2038: 25 MW x 16 hr, Liquid Air Storage
2039: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr, Liquid Air Storage
2043: 2.5 MW, Demand Response
2042-2045: 225 MW x 4 hr, Lithium-ion
2044: 50 MW, Solar w/ 50 MW x 4hr, Storage
16
Load reduction of 152 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 582 of 1057
DRAFT ONLY
Reliability Study Results
•14% planning margin without Colstrip and non-
dispatchable resources is too low.
•LOLP analysis was re-studied without Colstrip to
determine the required planning margin to achieve 5%
LOLP with NG CTs-this resulted in a ~16% planning
margin
•The resulting draft reliability metrics for the PRS are:
17
Reliability Metric Draft PRS Result TAC 2 Adequate
System Result
LOLP 7.0%4.9%
LOLH 3.10 1.85
LOLE 0.25 0.16
EUE 552.3 MWh 318.7 MWh Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 583 of 1057
DRAFT ONLYPRS Comparison to Corporate Clean
Electricity Goal
Goal: Serve customers with 100% cost effective clean electricity
-
200
400
600
800
1,000
1,200
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
"Clean" Market Purchases
Clean Generation
Sales Forecast
PRS meets 89% of corporate goal by 2027
Notes:1) Prior to 2030, Avista is a net energy seller to the market2) “Clean” market purchases is measured as the regional
generation mix’s CO2 mix compared to a CCCT18
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 584 of 1057
DRAFT ONLY
PRS: Greenhouse Gas Emissions Forecast
(1.0)
(0.5)
-
0.5
1.0
1.5
2.0
2.5
3.0
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
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Net Market Purchases/Sales
New Resources
Current Resources
2018 Actual
Total Net Emissions
80% to 85% net reduction after 2027
19
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 585 of 1057
DRAFT ONLY
Ce
n
t
s

p
e
r

k
W
h
Re
v
e
n
u
e

R
e
q
u
i
r
e
m
e
n
t

(
M
i
l
l
i
o
n
s
)
Rev. Req.
Rev. Req. + 1 Stdev
Rev. Req. 95th Percentile
Avg Rate
PRS: Cost/Rate Forecast
20
System PVRR: $11.777 billion
2030 Rate: 10.3 cents/kWh
2045 Rate: 14.1 cents/kWh
Note: Assumes non-power supply modelled costs escalate at 2 percent per year
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 586 of 1057
DRAFT ONLY
In
c
r
e
m
e
n
t
a
l

C
o
s
t
Cost Comparison between PRS and LC
Portfolio w/o CETA
Notes: State allocation factors and resource designation will affect these results for each state21
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 587 of 1057
DRAFT ONLY
Avoided Cost of Generation Calculation
Methodology
•Energy value:hourly mark to market value of delivered energy in the wholesale
market (i.e. Mid-C index).
•Capacity value:total portfolio revenue requirement difference between a portfolio
meeting capacity targets versus a portfolio only relying on the spot energy market.
The difference is divided by the added capacity additions (MW) to estimate $ per kW.
Rates are levelized and tilted to begin with first deficit.
•Clean premium:total portfolio revenue requirement difference between a portfolio
meeting CETA versus a portfolio only meeting the capacity requirements. This
difference is divided by added generated MWh. Rates are levelized and tilted to begin
with first expected acquisition year.
•Clean premium with tax incentives: Same as clean premium calculation except the
federal tax subsidies continue.
22
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 588 of 1057
DRAFT ONLY
Avoided Costs
23
Year
(S/MWh)
On-
($/MWh)
Off-
($/MWh ($/MWh)
($/MWh
($/kW-
year)
2021 19.67 22.64 0.00 0.0
2022 19.98 22.75 9.33 0.0
2023 20.44 23.05 9.52 0.0
2024 21.61 24.09 9.71 0.0
2025 22.76 25.19 9.90 0.0
2026 24.27 26.40 10.10 97.3
2027 23.57 25.27 10.30 99.3
2028 25.02 26.26 10.51 101.2
2029 25.92 26.80 10.72 103.3
2030 26.72 27.08 10.93 105.3
2031 29.46 29.66 11.15 107.4
2032 29.78 29.95 11.38 109.6
2033 31.22 30.74 11.60 111.8
2034 32.83 31.94 11.83 114.0
2035 33.66 32.64 12.07 116.3
2036 35.82 34.82 12.31 118.6
2037 36.12 34.58 12.56 121.0
2038 38.81 37.40 12.81 123.4
2039 38.60 37.13 13.07 125.9
2040 38.52 36.80 13.33 128.4
2041 39.09 37.74 13.59 131.0
2042 38.98 37.99 13.87 133.6
2043 40.24 39.51 14.14 136.2
2044 46.10 45.29 14.43 139.0
2045 43.94 43.11 14.71 141.8
15 yr Levelized 24.58 26.11 9.38 58.5
20 yr Levelized 26.44 27.55 9.87 67.8
25 yr Levelized 27.86 28.77 10.27 74.3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 589 of 1057
DRAFT ONLY
Challenges and Considerations
•Ultimate disposition of Colstrip
•State resource allocation
•Achieving Avista clean electricity goal
•Transmission needs and issues
–Integration of transmission & distribution needs into a fully Integrated Resource Plan
–System impacts of third party generation resources
•Storage issues
–Physical requirements for resource adequacy and grid reliability
–Economic needs for integration of renewable generation
–Storage technology and cost improvements
•Rulemaking and permitting impacts on the preferred resource options
•Market development to accommodate increased variable generation and
acquisition
24
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 590 of 1057
2020 Electric Integrated Resource Plan
Draft Portfolio Scenario Analysis
James Gall, IRP Manager
Fifth Technical Advisory Committee Meeting
October 15, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 591 of 1057
DRAFT
Scenario Overview
•Use same electric price forecast-but different resource
assumptions.
•Use optimization to create portfolio, but use different
constraints for each scenario.
•View financial results of each portfolio along with
resource selection.
•Portfolio results with different market assumptions will be
provided at the next TAC meeting.
•No reliability analysis are completed for portfolio
scenarios.
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 592 of 1057
DRAFT
Portfolio
outside of
portfolio
constraints
Efficient Frontier Overview
Ri
s
k
Cost
Least cost-
highest risk
portfolio
Highest
cost-least
risk portfolio
In-efficient
portfolio
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 593 of 1057
DRAFT
Scenarios
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)
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 594 of 1057
DRAFT
20
3
0

P
o
w
e
r

S
u
p
p
l
y

C
o
s
t

S
t
d
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v
2021-45 Levelized Annual Revenue Requirement
Least Risk
25/75
50/50
75/25
Least Cost
Efficient Frontier Results
#4: Rely on Energy Markets Only
#2: Least Cost Plan w/o CETA
#7: Colstrip Extended w/o CETA
#1: PRS
#10: LC w/
Tax Credits
Extended#8: Colstrip
Extended w/ CETA
#3 Clean Resource Plan
#11 Clean
Resource Plan w/ Tax Credits
#5 No CTs by 2045
#6 Least Cost w/o P/S or Long Lake
#9: LC w/ higher P/S costs
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 595 of 1057
DRAFT
2030 Portfolio Resource Selection
6
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 596 of 1057
DRAFT
2040 Portfolio Resource Selection
7
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 597 of 1057
DRAFT
2045 Portfolio Resource Selection
8
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 598 of 1057
DRAFT
Annual Cost Comparison
9
PVRR (Millions)Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 599 of 1057
DRAFT
Rate Comparison
sorted by 2045 rates
10
Cents per kWh
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 600 of 1057
DRAFT
Portfolio Tail Risk
(95th percentile minus expected cost, excludes Social Cost of Carbon)
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 601 of 1057
DRAFT
PVRR Risk Adjusted Comparison
Sorted by TailVar w/o Social Cost of Carbon (SCC)
12
$11.0
$12.0
$13.0
$14.0
$15.0
$16.0
$17.0
10. LeastCost w/federal taxcreditsextended
12. LCPLowEconomicGrowth
4. Rely onEnergyMarketsOnly w/oCETA
1. LeastCost Plan/PRS
11. CRPw/ federaltax creditsextended
8. Colstrip2035 w/CETA
14. LCP w/LancasterPPA
9. LCP w/Higher P/Scost
6. LCP w/oPS/Hydro 7. Colstrip2035 w/oCETA
2. LCP-w/o CETA 2. LCP-w/o CETA EfficientFrontier:25%Risk/75%Cost
13. LCPHighEconomicGrowth
3. CleanResourcePlan(CRP)
EfficientFrontier:50%Risk/50%Cost
5. CRP-No CTs EfficientFrontier:75%Risk/25%Cost
EfficientFrontier:Least Risk
PV
R
R

(
B
i
l
l
i
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n
s
)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 602 of 1057
DRAFT
Annual Greenhouse Gas Comparison
13
Mi
l
l
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n

M
e
t
r
i
c

T
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s

o
f

C
O
2
(e
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)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 603 of 1057
DRAFT
Annualized Greenhouse Gas Emissions
(Levelized using 2.5% discount rate)
2.64
1.36
1.19
1.10
1.08
0.93
0.86
0.83
0.83
0.82
0.80
0.80
0.80
0.74
0.69
0.66
0.63
0.63
0.63
0.00 0.50 1.00 1.50 2.00 2.50 3.00
2018 (excluding market effects)
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
4. Rely on Energy Markets Only w/o CETA
2. LCP- w/o CETA
14. LCP w/ Lancaster PPA
10. Least Cost w/ federal tax credits extended
13. LCP High Economic Growth
6. LCP w/o PS/Hydro
1. Least Cost Plan/ PRS
9. LCP w/ Higher P/S cost
12. LCP Low Economic Growth
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 25% Risk/75% Cost
Efficient Frontier: 50% Risk/50% Cost
3. Clean Resource Plan (CRP)
5. CRP- No CTs
11. CRP w/ federal tax credits extended
Annualized Millions of Metric Tons of Greenhouse Gases
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 604 of 1057
DRAFT
Ch
a
n
g
e

i
n

L
e
v
e
i
z
e
d

C
o
s
t

D
e
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t
a

f
r
o
m

P
o
r
t
f
o
l
i
o

#
2

(M
i
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l
i
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n
s
)
Change in Levelized GHG Emissions from Portfolio #2 (Millions)
Cost vs GHG Emissions
#1-PRS
#3-Clean Resource Plan
#4-Rely on Energy Markets Only (w/o
CETA)
#5-Clean Resource Plan-No CTs
#6-LCP w/o PS/Hydro #7-Colstrip 2035 w/o CETA
#8-
Colstrip 2035 w/
CETA
#10-LCP w/
Federal Tax Credits Extended
#9-LCP w/
Higher P/S Cost
#11-CRP w/ Federal
Tax Credits Extended
#12-LCP Low Economic
Growth
#14-LCP w/ Lancaster PPA extended
#13-LCP High
Economic Growth
15
Implied Carbon Levelized Carbon Prices#1. PRS: $27/metric ton
#2. CRS: $120/metric ton
#5. CRS No CTs: $141/metric ton
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 605 of 1057
DRAFT
Scenario Results Summary Table
16 Note: Costs do not include Social Cost of Carbon
Portfolio
Number Portfolio name
Cost 2021-
2045 (PVRR)
(millions)
Cost 2021-
2030 (PVRR)
(millions)
2030 Risk
(millions)
2030 Rate
(c/kWh)
2045 Rate
(c/KWh)
Levelized
R.R.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 606 of 1057
Appendix
Detailed Resource Portfolios
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 607 of 1057
DRAFT1) Preferred Resource Strategy
Least Reasonable Cost Plan
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 85 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2033: 25 MW x 16 hr, Liquid Air Storage
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 25 MW x 16 hr, Liquid Air Storage
2038: 25 MW x 16 hr, Liquid Air Storage
2039: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr, Liquid Air Storage
2043: 2.5 MW, Demand Response
2042-2045: 225 MW x 4 hr, Lithium-ion
2044: 50 MW, Solar w/ 50 MW x 4hr, Storage
18
Load reduction of 152 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 608 of 1057
DRAFT2) Least Cost Plan
w/o CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 52 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027: 245 MW, Natural Gas CT
2031-2040
2031: 75 MW, Mid-C PPA Renew
2033: 25 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 84 MW, Natural Gas CT
2036: 9 MW, Demand Response
2038: 25 MW x 16 hr, Liquid Air Storage
2040: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041-2042: 50 MW x 16 hr, Liquid Air Storage
2043-2045: 450 MW x 4 hr, Lithium-ion
19
Load reduction of 131 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 609 of 1057
DRAFT
3) Clean Resource Plan
100% net clean by 2030
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2025-2030: 39 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027-2029: 300 MW, NW Solar
2028-2030: 100 MW, Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW Long Lake 2nd
Powerhouse
2033: 50 MW, NW Solar
2035: 55 MW, Northeast CT retired
2036-2040: 125 MW Solar w/ 125 MW x 4 hr. Storage
2038: 10 MW Solar
2039: 50 MW x 4 hr, Liquid Air Storage
2033-2040: 46 MW, Demand Response
2041-2045
2041-2043: 300 MW Wind PPA Renew
2042-2044: 75 MW x 16 hr Liquid Air Storage
2045: 5 MW Solar
2045: 50 MW Solar w/ 50 MW x 4 hr Storage
2045: 50 MW x 4 hr, Lithium-ion
20
Load reduction of 175 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 610 of 1057
DRAFT4) Rely on Energy Markets Only
(no capacity or renewable additions)
2021-2030
2026: 222 MW, Colstrip removed
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2031-2040
2035: 55 MW, Northeast CT retired 2041-2045
21
Load reduction of 102 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 611 of 1057
DRAFT5) 100% Net Clean by 2027
and No CTs by 2045
2021-2030
2022: 150 MW, Solar
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2025-2027: 39 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027-2029: 300 MW, NW Solar
2028-2030: 100 MW, NW Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd
Powerhouse
2033: 50 MW, NW Solar
2033-2035: 46 MW, Demand Response
2035: 55 MW, Northeast CT retired
2036-2040: 135 MW Solar w/ 125 MW x 4 hr, Storage
2039-2040: 250 MW x 16 hr Liquid Air Storage
2040: 50 MW Pumped Hydro
2035: 154 MW, Rathdrum CTs removed
2041-2045
2041-2043: 300 MW Wind PPA Renew
2043: 9 MW, Kettle Falls CT removed
2043: 25 MW, Boulder Park removed
2043-2045: 50 MW x 4 hr, Lithium-ion
2042-2044: 125 MW x 16 hr Liquid Air Storage
2045: 10 MW Solar
2045: 50 MW Solar w/ 50 MW x 4 hr, Storage
2045: 175 MW Pumped Hydro
2045: 100 MW Small Nuclear
2045: 75 MW Biomass
2045: 302 MW, Coyote Springs 2 removed
22
Load reduction of 174 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 612 of 1057
DRAFT
6) Least Cost Plan
w/o pumped storage or Long Lake
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 129 MW, Natural Gas CT
2027: 30 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-2032: 55 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 84 MW, Natural Gas CT
2039: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW Wind PPA
Renew
2042: 25 MW x 16 hr, Liquid Air Storage
2043-2045: 150 MW Solar w/ 150 MW x 4 hr, Storage
2044-2045: 75 MW x 4 hr, Lithium-ion
2044: 25 MW x 16 hr Liquid Air Storage
23
Load reduction of 149 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 613 of 1057
DRAFT
7) Colstrip Extended to 2035 w/o CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 25 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2028-2030: 61 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 25 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035-2036: 252 MW, Natural Gas CT
2036: 100 MW, MT Wind
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042: 25 MW x 16 hr Liquid Air Storage
2042-2045: 450 MW x 4 hr, Lithium-ion
24
Load reduction of 129 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 614 of 1057
DRAFT
8) Colstrip Extended to 2035 w/ CETA
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2028: 39 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032-2035: 46 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 200 MW, MT Wind
2036: 132 MW, Natural Gas CT
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2042-2045: 75 MW, Solar w/ 75 MW x 4 hr, Storage
2042-2045: 125 MW x 4 hr, Lithium-ion Storage
2045: 25 MW x 16 hr Liquid Air Storage
25
Load reduction of 143 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 615 of 1057
DRAFT9) Least Cost Plan
w/ higher pumped storage cost
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2028: 109 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 90 MW, Natural Gas CT
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 25 MW x 16 hr Liquid Air Storage
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2035-2040: 100 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW, Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2044: 25 MW x 16 hr Liquid Air Storage
2044: 10 MW, Solar
2044: 25 MW x 4 hr, Lithium-ion
2045: 50 MW x 4 hr, Lithium-ion
2045: 50 MW Solar w/ 50 MW x 4 hr Storage
26
Load reduction of 155 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 616 of 1057
DRAFT10) Least Cost Plan
w/ Federal Tax Credits Extended
2021-2030
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 175 MW Pumped Hydro
2026: 283 MW, Lancaster PPA expires
2027: 100 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2027-2030: 60 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 25 MW, Demand Response
2035: 84 MW, Natural Gas CT
2035: 55 MW, Northeast CT retired
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2041-2042: 300 MW, Wind PPA Renew
2043: 25 MW, Pumped Hydro
2044-2045: 150 MW NW Solar
2044-2045: 150 MW, Solar w/ 150 MW x 4 hr Storage
2044-2045: 100 MW x 4 hr, Lithium-ion
27
Load reduction of 144 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 617 of 1057
DRAFT11) Clean Resource Plan
w/ Federal Tax Credits Extended
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2026: 39 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 200 MW, MT Wind
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027-2029: 300 MW, NW Solar
2027: 8 MW, Post Falls Upgrade
2028: 50 MW, Solar
2028: 50 MW, Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd Powerhouse
2033: 60 MW, Solar
2033-2035: 46 MW, Demand Response
2035: 55 MW, Northeast CT retired
2036-2040: 135 MW, Solar w/ 125 MW x 4 hr Storage
2039: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2042: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2043-2045: 200 MW x 4 hr, Lithium-ion
2045: 55 MW, Solar w/ 50 MW x 4 hr of Storage
28
Load reduction of 173 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 618 of 1057
DRAFT12) Least Cost Plan
w/ Low Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2027: 55 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 75 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 68 MW Long Lake 2nd
Powerhouse
2038-2039: 30 MW Demand Response
2041-2045
2041: 25 MW x 4 hr, Lithium-ion
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2044-2045: 75 MW Solar w/ 75 MW x 4 hr Storage
29
Load reduction of 152 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 619 of 1057
DRAFT13) Least Cost Plan
w/ High Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2029: 85 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 200 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2030: 68 MW Long Lake 2nd
Powerhouse
2031-2040
2031-2033: 75 MW, Mid-C PPA Renew
2035: 84 MW Natural Gas CT
2035: 55 MW, Northeast CT retired
2037-2040: 100 MW x 16 hr Liquid Air Storage
2041-2045
2041-43: 100 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW Wind PPA Renew
2043-2045: 125 MW x 4 hr, Lithium-ion
2044: 25 MW Pumped Hydro
2044-2045: 75 MW Solar w/ 75 MW x 4 hr Storage
30
Load reduction of 152 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 620 of 1057
DRAFT14) Least Cost Plan
w/ Lancaster PPA Extended Five Years
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2027: 8 MW, Post Falls Upgrade
2030: 30 MW, Demand Response
2031-2040
2031-2032: 75 MW, Mid-C PPA Renew
2031-2032: 55 MW Demand Response
2032: 257 MW, Lancaster PPA expires
2032: 200 MW MT Wind
2032: 84 MW Natural Gas CT
2032: 68 MW Long Lake 2nd
Powerhouse
2035: 55 MW, Northeast CT retired
2035: 84 MW Natural Gas CT
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW, Solar w/ 25 MW x 4 hr Storage
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW, Wind PPA Renew
2042-2045: 225 MW x 4 hr, Lithium-ion
2043: 25 MW x 16 hr Liquid Air Storage
2044: 50 MW, Solar w/ 50 MW x 4 hr Storage
2045: 2.5 MW, Demand Response
31
Load reduction of 141 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 621 of 1057
DRAFT
Least Risk Plan
2021-2030
2022: 150 MW, NW Solar
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 257 MW, Lancaster PPA expires
2027: 308 MW, Natural Gas CCCT
2027-2028: 200 MW, MT Wind
2028-2030: 300 MW, NW Solar
2029-2030: 200 MW, NW Solar
2029-2030: 200 MW, Small Nuclear
2030: 308 MW, Natural Gas CCCT
2031-2040
2035: 55 MW, Northeast CT retired 2041-2045
2045: 5 MW, Solar
2045: 100 MW, NW Wind
2043-45: 50 MW, Mid-C PPA Renew
32
Load reduction of 67 aMW due to Energy Efficiency by 2040
Note: The least Least Risk Portfolio minimizes risk for 2030
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 622 of 1057
DRAFT
25% Risk/ 75% Cost Plan
2021-2030
2022: 50 MW, NW Solar
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Solar
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 175 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 30 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2030: 170 MW, Solar w/ 25 MW x 4 hr Storage
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 55 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 25 MW x 16 hr Liquid Air Storage
2038: 25 MW x 16 hr Liquid Air Storage
2039: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW, Pumped Hydro
2044: 5 MW
2044: 25 MW x 4 hr, Lithium-ion
2044: 25 MW x 16 hr Liquid Air Storage
2045: 50 MW, Solar w/ 50 MW x 4 hr Storage
2045: 100 MW, NW Wind
2045: 50 MW x 4 hr, Lithium-ion
33
Load reduction of 143 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 623 of 1057
DRAFT
50% Risk/ 50% Cost Plan
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2026-2030: 60 MW, Demand Response
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2028-2030: 300 MW, Solar w/ 300 MW x 4hr storage
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 25 MW, Demand Response
2035: 84 MW, Natural Gas CT
2035: 55 MW, Northeast CT retired
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2044: 100 MW x 16 hr Liquid Air Storage
2043-2044: 75 MW x 4 hr, Lithium-ion
2044: 50 MW, solar w/ 50 MW x 4hr storage
2045: 25 MW Pumped Hydro
34
Load reduction of 146 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 624 of 1057
DRAFT
75% Risk/ 25% Cost Plan
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 25 MW, NW Solar
2026: 257 MW, Lancaster PPA expires
2027: 308 MW, Natural Gas CCT
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2028-2030: 300 MW, Solar w/ 300 MW x 4hr storage)
2030: 50 MW, Small Nuclear
2031-2040
2035-2039: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2039: 30 MW, Demand Response
2041-2045
2042: 25 MW, Demand Response
2043: 25 MW, Pumped Hydro
2044: 150 MW x 4 hr, Lithium-ion
2045: 25 MW, Pumped Hydro
35
Load reduction of 125 aMW due to Energy Efficiency by 2040
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 625 of 1057
DRAFT
Future Scenarios For Next TAC meeting
•Alternative load forecasts
–Electrification and roof top solar
–Economic cycles
•Electric market price scenarios
–Each of the previous scenarios w/ alternative prices
–Least cost strategies w/ alternative prices
•Other scenarios?
–For this IRP or the next
36
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 626 of 1057
DRAFT
Carbon Abatement Curve Proposal
•Use “Expected Case” market forecast
•No change to capacity build
•Add generator/load in 100 MW in NW area
•Estimate “system” emission reduction by difference between 2030 expected case and
sensitivity
•Estimate cost of reduction concept
•Calculate the estimated societal $/metric ton
•Abatement options in Avista’s system
–Generation sources:
•Add: solar, wind, hydro, storage, storage + renewable
•Remove: CCCT, CT, coal
–End uses: water heater, furnaces, (to NG, away from NG), energy
efficiency
–Transportation: Electric vehicle vs gasoline/diesel
•Results at next TAC meeting
37
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 627 of 1057
Attendees: TAC 5, Tuesday, October 15, 2019 at Avista Headquarters in Spokane, Washington:
Logan Callen, City of Spokane; Darrell Soyars, Avista; Terrence Browne, Avista; Garrett Brown, Avista; Zach Genta, Clenera; Clint Kalich, Avista; Linda Gervais, Avista; Justin Cowley, Clear Water Paper; John Barber, Rockwood Retirement Community; Dave Van Hersett, Customer; Kirsten G. Wilson, WA DES Energy Program; Jennifer Snyder, Washington Utilities and Transportation Commission; Jason Thackston, Avista; Cadie
Olsen, City of Spokane; Kathlyn Kinney, Biomethane, LLC; Tom Pardee, Avista; James Gall, Avista; Collins Sprague, Avista; Greg Rahn, Avista; John Lyons, Avista; Rachelle Farnsworth, Idaho Public Utilities Commission; Amy Wheeless, Northwest Energy Coalition; Jim Le Tellier, 350 Spokane; David Howarth, National Grid Ventures; Michael Eldred, Idaho Public Utilities Commission; Barry Kathrens, 350 Spokane.org; and Grant
Forsyth, Avista.
Phone Participants:
John Chatburn, Idaho Office of Energy and Mineral Resources; Damon Zentz, City of
Spokane; Nancy Esteb, Renewable Energy Coalition; and remaining phone participants
did not identify themselves.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses are in italics, and
significant points raised by presenters that are not shown on the slides are also
included.

Introductions, Updates and TAC 4 Recap, John Lyons
No additional notes or commentary.

Energy Imbalance Market Update, Scott Kinney
Dave Van Hersett: What is an organized market? Will talk about organized markets later
in the presentation.
John Barber: Is this just a bunch of people calling back and forth? Yes, but there is
more electronic communication now.
Dave Van Hersett: Kind of like the ICP? Yes, going back quite a ways.
Kathlyn Kinney: What percentage of electricity do we have to buy? Depends. Spring,
we are a net seller. Summer, we may go to market, usually at the Mid-Columbia trading
prices. It changes depending on the company’s needs and the market prices.
Jim Le Tellier: Hydro percentage in mix? About 50%.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 628 of 1057
Dave Van Hersett: Is CAISO by hour? It’s a day ahead, 15 minute and a five minute
market. Looking for optimized resources to impact dispatch cost. Readjust resources
differently based on economics as we get closer to real time.
Dave Van Hersett: Who owns CAISO? A government agency with a board selected by
the Governor of California.
Dave Van Hersett: Easier to construct [new resources]? Maybe, because it is looking at
a bigger footprint.
Dave Van Hersett: Savings? Cost savings for customers based on a past operations.
Dave Van Hersett: I’m struggling with what’s the downside since ours is among the
lowest cost in the region. Do we go up and others go down? Will talk about that later,
but we expect more revenues and cheaper dispatch.
Jason Thackston (Slide 7): We do this already outside the day, but not inside the hour
Since the 1980s we have been doing this on the hour.
Dave Van Hersett: Saying hour-by-hour, now into the 5 minute market? Yes, good way
of putting it.
Cadie Olsen: What drove early adopters? Renewable energy penetration. Lower
dispatch (30 - 35%), load following costs, and some by Commissions and economics.
Jim Le Tellier: Why did PacifiCorp join? Utah, load pockets in Oregon. Better
optimization between both utilities.
Slide 13: A little bit optimistic numbers based on methodology, but they are indicative.
Dave Van Hersett: Gross revenue for Avista? $800 to $900 million gross revenue
requirement required. This is just the in-hour part.
Jason Thackson: 3% of power supply expenses.
Jim Le Tellier: Does the entire EIM share a transmission grid? Yes, participants still own
their transmission. They allocate a percentage for market transactions. Allow anything
to be used within the hour if not already paid for. Transmission is in effect free for EIM
transactions.
Dave Van Hersett: Will EIM reduce staff? No, we are actually adding bodies.
Technology and models allow us to trade within the hour.
Slide 15 – It was getting difficult for us to find a trading partner around the summer of
2018. There was not enough market liquidity. All of the utilities around us –
Northwestern Energy, BPA, Idaho Power – joined or are joining the EIM.
Jim Le Tellier: Where is Rattlesnake Wind located? The Othello area, in Washington.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 629 of 1057
Scott Kinney: PURPA changes. Recent changes in Washington expanded size
qualifying for different costs and from 5 to 15 years. We have seen additional requests
for PURPA. Prices are still falling, probably for a period of time as more renewables are
added to the system.
Clint Kalich: Energy only. But, if bringing capacity, projects will get more benefit.
Capacity over winter nights will be getting even more benefit.
Who do we talk to about PURPA? Either Clint Kalich or Steve Silkworth.
Dave Van Hersett: Is there a disadvantage to being in this group? The large technology
commitment is costly. Do they get to call on our resources? Only if we voluntarily bid in.
Jennifer Snyder: How often? Every five minutes. Hydro flex makes sense every hour.
Dave Van Hersett: Typically, what is the technology needed for the EIM? Outage
management system, bidding system, and settlement system.
Dave Van Hersett (slide 17): $6 million net. No, gross. 8 to 9-year breakeven. Show
chart 18. Most utilities actually seeing 3 to 5 times the study benefits.
Jennifer Snyder: When was the study done? 2017 and updated in 2018; and cost done
in 2015 and updated in 2018.
Dave Van Hersett: If Avista keeps getting more renewables, does this help? Absolutely,
expect about a 35% reduction in costs to integrate renewables. Flex hour hydro allows
us to bid in.
Dave Van Hersett: In the long run, higher base of renewables might be better in the long
term. Yes, Idaho Power is similar to us and we see a similar market potential.
Jim Le Tellier: Nice to have economic benefits, but many non-economic benefits that
they might have even joined for.
Cadie Olsen: In the penultimate slide, how many city people are you interfacing with?
Our citizens are our customers with 700 connections plus a generation interconnect.
Touchpoints at generators. Not anticipating city resources being bid into the EIM.
Jim Le Tellier: As far as interconnection renewables, are they being drawn from other
states? Wind from Montana? Yes, includes renewables from other areas.
Kirsten Wilson: Any preliminary evaluation of the shutdowns with PG&E? Some
assessment, but minimal from the EIM’s perspective. More exposure in California with
the only participant.
Scott Kinney: More opportunity to integrate resources. Possibility depending on size and
capability and controls. Costs may exceed benefits.
Jim Le Tellier: As Colstrip goes offline, will there be more gas or renewables? James
will be covering that later today.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 630 of 1057
Logan Callen (Slide 18): PSE? More aggressive air study assumption and not as
integrated through BPA.
Amy Wheeless: As Seattle comes online, will there be more benefit for PSE? Yes, we
would expect it.
Dave Van Hersett: Does this affect our ability to stand alone? No, we are required to be
resource sufficient to be able to bid in to the EIM.
Scott Kinney: People vs. algorithms. Dispatch is fully automated for dispatch changing
but still have a final human check. This may change over time.

Storage and Ancillary Storage Analysis, Xin Shane
Dave Van Hersett: What is an example of an ancillary service? Regulation.
Dave Van Hersett: Can you get all out that you put in? No, only about 70% round trip
efficiency, which is the downfall of this type of storage.
Clint Kalich (Slide 6): Only about 10% of the 1 MW cap to pull hard off system. Only a
small amount of the total can be quickly used.
Barry Kathrens: Is capacity seasonal? Did not consider it in this study. Engineers say
there are many different factors like temperature.
Rachelle Farnsworth: Is the typical performance for this type of battery to charge and
recharge? Yes, when price is high it is discharging and when low it is charging.
John Barber: Was Avista’s battery shut down? Yes. It was the first one made by the
manufacturer and was shut down for mechanical issues.
Jason Thackston: The battery had a leak on a customer’s premises, so we removed it.
Cadie Olsen: Did you learn anything different from other empirical studies? Speed
affecting overall efficiency, system setting comprehensive operational mod, testing
linear model and refining it.
Kirsten Wilson: Intent was to study quite a few (seven) operating scenarios and how
batteries responded. Different parts worked on different streams.
David Howarth: When you say one third, is that equivalent to water availability or two
thirds hydro? Capped two units on Noxon Rapids and one unit on Cabinet Gorge –
cascading system.
Jim Le Tellier: Pumping from lower to higher levels? Yes, that is what we are studying.
Two reservoirs with a two way turbine.
Dave Van Hersett: Two way is pump or generate? Yes.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 631 of 1057
Dave Van Hersett: Could we do that at Noxon Rapids?
Jason Thackston: Not a reservoir at Noxon. Hard when licensing is challenging, not a
closed system.
Jim Le Tellier: With the EIM there could be pumped storage in other regions. Some in
Montana is already permitted.
Jim Le Tellier: Astronomical starting cost, but a lot more benefit going forward to
consider.
Clint Kalich: Some comments for the regulators in the room to consider on slide #12. It
is difficult and complicated to do these studies. If we can create ancillary services, the
value lies in arbitrage. The left 1/3 of hydro in the portfolio, and then saw the benefits of
arbitrage. Most of the value is when we get energy in the system whether owned, PPA,
or cheaper to just store renewables.
David Howarth: With the existing hydro flexibility on the system, wondering on a low
hydro year how it affects flexibility. Modestly ancillary benefit in low hydro years.
Dave Van Hersett: Are we not looking at pumped storage yet? Next presentation.
Amy Wheeless: Not that many pumped storage projects in the northwest. Got to wait
until after lunch.

Preliminary Preferred Resource Strategy, James Gall
Jim Le Tellier: Does Avista have an R&D department? We keep up with developments
and participate in new technologies. Idaho funds some R&D. We dabble, but are not
focused on R&D.
Jason Thackston: University District, Energy Impact Partners Fund investor and Clean
Energy Grants.
Scott Kinney (Slide 3): How much could we drop the gap by renewing contracts as they
expire, economic competition, and repowering of worn out wind projects?
Matt Nykiel: How are Idaho RECs managed and sold. RECs are recorded and
transferred in WREGIS.
Jim Le Tellier: The goal doesn’t sound real positive. If you have to have new
technology, we want to see Avista as a leader.
Jason Thackston: We are working in the western US and using the Clean Energy Grant.
Jennifer Snyder: You are part of NEAA too.
Kathlyn Kinney: Does EIM help? It helps us manage, but is not a capacity market.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 632 of 1057
Scott Kinney: EIM participants have to show how they can meet their own resource
needs.
Matt Nykiel (Slide 4): Are there asterisks to Avista’s goals [100% clean] that we can
read about?
Jason Thackston: The web site has a section. It is correct there is not a lot of detail on
it. We need to see improvement on energy storage. 6 pm on a January night is our peak
load and battery storage is not there yet. We are still working on it ourselves. Your
definition of affordability may be different than mine. Hypothetically, is 15% worth it?
Across the river from here, no. And we have to do this in a way that maintains reliability.
Matt Nykiel: Is Avista conducting a survey showing what is affordable?
Barry Kathrens: Is this a thing from the Nadine [Woodward mayoral] debate? No,
difference was between completely 100% renewable versus an aspirational goal.
Sometimes the details in politics don’t always line up.
Amy Wheeless (Slide 5): Hydro from BPA, doesn’t respond to an RFP? We can’t just
assume BPA hydro availability. They have told us an RFP is not how they typically want
to interact.
Jim Le Tellier: BPA power is $90? Yes, that is what they are required to sell at.
Fred Huette: Transmission is a separate discussion. BPA hydro, know they have
interest in a PGE capacity deal. Difficulties in how to model it, but not leave an
impression that we are not interested in it. Maybe we could model it as northwest
capacity.
Matt Nykiel: What is social cost of carbon cost? $80 for Washington portion, see the last
TAC meeting presentations for more details.
Rachelle Farnsworth (Slide 6): How will you be excluding additional costs for Idaho?
Like the Social Cost of Carbon. Model solves for a peaker, only Washington has the
cost. Then we allocate costs between the two states. Would depend on what we would
do without the law. If Idaho needs wind, they pay their part. If not, all of the costs go to
Washington. Also assign price of RECs, incremental cost of the resource over market,
to transfer from Washington to Idaho.
Rachelle Farnsworth: Building in costs. Need to keep track of additional costs that
should not be attributed to Idaho.
Matt Nykiel: If the decision is made to keep it left open, how would Colstrip get allocated
[after 2025]? Not sure yet, it would be a Rates questions and handled outside of the
IRP.
Rachelle Farnsworth: Just because Washington doesn’t take the electrons, there are
still remediation costs they are responsible for.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 633 of 1057
Jennifer Snyder: Treating things as of today until 2025. After that, CETA allows recovery
for remediation.
Matt Nykiel: Incremental Idaho costs post 2025.
Jim Le Tellier: On Colstrip, if Westmoreland completely goes under, do the five owners
have other coal sources.
Jason Thackston: Six owners, but the air permit doesn’t permit new coal. The new coal
contract is being finalized.
Slide 11: Red is cost effective, black is not cost effective and orange maybe cost
effective.
Amy Wheeless (Slide 11): Is this based on AEG? Yes. Water heating does – with and
without CETA required device. Not sure why yet. Didn’t originally include. Added it back
two weeks ago and will follow up later.
Fred Huette: Not CETA, 1444, unless they (Commerce) grants some sort of extension.
With a cost per kW-year well under $100/kW-year. What is the name of the consultant?
AEG.
Jennifer Snyder: For variable peak pricing and time of use, are there plans to have
pilots? Still have to figure that out. Probably about 10 different things that will still have
to be sorted out to make these happen.
Fred Huette (Slide 13): Effectively, Montana wind is a 40% capacity value. Yes, capacity
contribution could be different. All sites are not equal. Also, if it is really cold here and in
Montana, they [wind turbines] shut down about 25 degrees below zero. Probability of
minus 25 in Montana and really cold here.
Fred Huette: Really first of utilities putting direct value for Montana winter wind capacity.
May consider across Montana. Appreciate the work.
Kathlyn Kinney: Where does renewable natural gas fit in? Who gets it and at what cost.
Levelized cost is $10 - $20 per Dth. You can sell the RIN to drive down the cost, but
then the renewableness goes away. Can it clean up gas? Yes. Will it be available?
Maybe, but will it go to power, the LDC, or will it even be developed? Not modeled yet,
but as its gets closer to 100%, renewable natural gas competes.
Jim Le Tellier: What is the problem with transmission? Is it off, transmission rights
allocation, and overbuilding wind. We own a portion of the line from Montana and have
a BPA contract for the rest.
David Howarth: What is long duration for storage? 40 hours per week.
Amy Wheeless (Slide 13): Not too many sites [pumped hydro]? Probably four to five
sites and one with long duration. Will require more time and money to find other viable
sites. What’s available particularly for open loop?
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 634 of 1057
Fred Huette (Slide 14): Liquid air. Haven’t hear much about it, but love the efficiency.
Yes, sub 70% efficiency, longer duration, long project life, and better if co-located with a
thermal plant.
Kirsten Wilson (Slide 15): Last round of the Clean Energy Grant funding went to
Tacoma for Praxair for liquid air storage. We tried for that funding too.
Matt Nykiel: What is the risk of a stranded asset, like a gas plant in 2026 or will be
required to be offset with RECs. It looks at all costs. Mandate, no.
Rachelle Farnsworth: How is the liquid air modeled? Based on cost projections.
Pumped hydro is number 1 for long duration, liquid air is number two for long duration
and lithium ion is number 3 when paired with solar for the tax credit plus the value of
short term storage.
Slide 17: Reliability. This is where portfolio could change. Colstrip is two relatively small
and significantly reliable units. 14% to 16% planning margin.
Fred Huette (Slide 17): Why does size make an impact on reliability? Redundancy of
two smaller units in the model. How much do we control versus how much we rely on
our neighbors. Yes, now; later not so much. This is a regional, not just and Avista issue.
Jennifer Snyder: Through 2045? No, 2030 only on the reliability study. We are on the
high side because of a single 320 MW resource out of 1,700 MW, the largest utility shaft
risk for a single unit in the west.
Scott Kinney (Slide 18): To clarify, this is system, not just Washington.
Clint Kalich: PURPA requires us to pay for energy and capacity, but we don’t pay a
clean premium under PURPA. We regard that as a put for the developer.
Matt Nykiel (Slide 24): Getting back to the transmission issue at Colstrip, there are at
least five other utilities. Does Avista lose out if they don’t make a decision? We are
contractually covered until the late 2020s.

Preliminary Portfolio Scenario Results, James Gall
No notes to add.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 635 of 1057
2020 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
Tuesday, November 19, 2019 Conference Room 130
Topic Time Staff
Introductions and TAC 5 Recap 9:30 Lyons

Review of PRS 9:45 Gall
Break 10:45 Portfolio Scenario Results 11:00 Gall Lunch 12:00

Portfolio Scenario Results Continued 1:00 Gall

Break 2:00 2020 IRP Action Items & Overview 2:15 Lyons Adjourn 3:00
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 636 of 1057
2020 Electric IRP
TAC Meeting Introductions and Recap
John Lyons, Ph.D.
Sixth Technical Advisory Committee Meeting
November 19, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 637 of 1057
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•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
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 638 of 1057
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 in all or some of the process
•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 studies we can do
–The earlier study requests are made, the more accommodating we can be
–June 15, 2019 was the latest to be able to complete studies in time for
publication
•Planning team is available by email or phone for questions or
comments between the TAC meetings
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 639 of 1057
TAC #5 Recap –October 15, 2019
•Introductions and TAC 4 Recap, Lyons
•Energy Imbalance Market Update, Kinney
•Storage and Ancillary Service Analysis, Shane
•Preliminary Preferred Resource Strategy, Gall
•Preliminary Portfolio Scenario Results, Gall
•Meeting minutes available on IRP web site at:
https://www.myavista.com/about-us/our-company/integrated-
resource-planning
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 640 of 1057
Today’s Agenda
9:30 –Introductions and TAC 5 Recap, Lyons
9:45 –Review of PRS, Gall
10:45 – Break
11:00 –Portfolio Scenario Results, Gall
Noon –Lunch
1:00 –Portfolio Scenario Results Continued, Gall
2:00 – Break
2:15 –2020 IRP Action Items and Overview, Lyons
3:00 –Adjourn
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 641 of 1057
2020 IRP and 2021 IRP Key Dates
•Draft IRP released to TAC members December 18, 2019
•Comments from TAC members are to be returned to Avista by
January 15, 2020
•IRP team will be available to address comments with
individual TAC members or the entire group if needed
•This IRP will be published February 28, 2020
•Washington IRP due date moved for all IOUs: draft due
January 1, 2021 and final IRP due April 1, 2021 to allow time
for CETA rule making
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 642 of 1057
2020 Electric Integrated Resource Plan
“Preferred” Resource Strategy
James Gall, IRP Manager
Sixth Technical Advisory Committee Meeting
November 19, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 643 of 1057
What Are Avista’s Physical Resource
Needs?
Main focus: Winter Peak:
Includes 14% Planning Margin + Reserves
Avista is also short in summer and on an annual average basis
beginning in 2027
-
500
1,000
1,500
2,000
2,500
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
Me
g
a
w
a
t
t
s
Available Resources Net Requirement
Gap
2026: 14 MW
2027: 302 MW
2030: 325 MW
2035: 495 MW
2040: 537 MW
Key Losses:
Colstrip: 2025*
Lancaster: 2026
Mid-C: 2030
Northeast: 2035
2 * Colstrip is assumed offline at the end of 2025 for planning purposes only. Avista’s ultimate decisions regarding
Colstrip are still to be determined.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 644 of 1057
Washington SB5116 Clean Requirements
2026: Colstrip can no longer serve Washington Load
2030: 80% energy delivered over a four-year period is clean and 20% can be RECs
2045: Goal to be 100% clean (will require new technology to stay under cost cap)
Gap
2030: 54 aMW
2035: 130 aMW
2040: 182 aMW
2045: 353 aMW
Key Losses:
Mid-C: 2030
Lind: 2039
Rattlesnake: 2040
Palouse: 2043
Assumes: Idaho customers sell offsets to Washington Customers
0
100
200
300
400
500
600
700
800
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
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2
7
20
2
8
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9
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Av
e
r
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g
e

M
e
g
a
w
a
t
t
s
Washington Existing Qualifying Resources
Idaho Available Hydro RECs
Washington Net Requirement
Washington Retail Sales
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 645 of 1057
Avista’s Clean Electricity Goal
0
200
400
600
800
1,000
1,200
20
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Av
e
r
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e
g
a
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t
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s
Total Existing Resources System Retail Sales (aMW)
2027: 100% net clean portfolio wide (cost effective considerations)
2045: 100% clean (cost effective considerations and technology)
Gap
2027: 339 aMW
2030: 360 aMW
2035: 426 aMW
2040: 448 aMW
2045: 562 aMW
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 646 of 1057
Resource Options
Clean
•Wind (WA/OR/MT)
•Solar (WA/ID/OR)
•Biomass (WA/ID)
•Hydro Upgrades (MS, LL)
•Hydro (Mid-C)
•Hydro (BPA)
•Geothermal
•Nuclear
•Energy Efficiency
•Demand Response
Other
•Natural Gas CT
•Natural Gas CCCT
•Storage
–Pumped hydro
–Lithium-ion batteries
–Liquid air
–Hydrogen
–Flow batteries
•Regional Transmission
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 647 of 1057
Preferred Resource Strategy Decision
Process
•Uses Mixed Integer Program (MIP) to find least cost solution
meeting capacity, energy, and renewable constraints for the system
between 2021 and 2045.
•Only known model with full co-optimization of energy efficiency and
demand response with supply side resources.
–Capable of co-optimization of T&D system with power system
•Accounts for societal preference Washington state planning criteria
–(Social Cost of Carbon, 10% cost advantage from energy efficiency,
upstream pipeline emissions, etc.)
•Non-modeled utility revenue requirements assumes an increase of
two percent per year.
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 648 of 1057
Changes Since Last TAC meeting
•Lowered Montana wind peak contribution due to
transmission losses
•Increased long-duration pumped storage
capacity contribution
•Increased planning margin in PRiSM to end with
a reliable system
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 649 of 1057
Reliability Study Results
•22.6% planning margin (14% + reserves) without Colstrip and non-
dispatchable resources is too low.
•The resulting draft reliability metrics for the PRS required an
equivalent 24.6% planning margin (equivalent to 350 MW of CTs):
8
Reliability
Metric
PRS (TAC 6)PRS (TAC 5)Updated
Adequate
System (w/o
Colstrip & w/
CTs)
TAC 2
Adequate
System
Result (w/
Colstrip &
CTs)
LOLP 5.3%7.0%5.2%4.9%
LOLH 2.02 3.10 1.79 1.85
LOLE 0.17 0.25 0.14 0.16
EUE 330 MWh 552 MWh 264 MWh 318.7 MWh
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 650 of 1057
0
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M
e
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a
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s
2017 IRP 2020 IRP
Energy Efficiency Results
45% increase
Note: excludes T&D losses9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 651 of 1057
Where is the Cost Effective Energy
Efficiency Savings?
Residential
40%
Commercial
49%
Industrial
11%
2040 Customer Class Savings
0.7
1.2
1.4
3.4
4.0
4.3
5.2
5.2
5.4
5.8
7.3
11.2
14.0
30.0
44.6
0 10 20 30 40 50
Office Equipment
Process
Miscellaneous
Food Preparation
Cooling
Heating
Electronics
Refrigeration
Motors
Appliances
Ventilation
Space Heating
Exterior Lighting
Water Heating
Interior Lighting
Average Megawatts
2040 Cumulative Savings
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 652 of 1057
Preferred Resource Strategy
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 175 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2025-2030: 76 MW, Demand Response
2026/27: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 32 MW, Demand Response
2035: 55 MW, Northeast CT retires
2035: 68 MW, Long Lake 2nd
Powerhouse
2036-40: 75 MW x 16 hr, Liquid Air Storage
2037: 1 MW Demand Response
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042: 2.5 MW, Demand Response
2042-2045: 300 MW Wind PPA Renew
2042-2045: 300 MW x 4 hr, Lithium-ion
2044: 55 MW, Solar w/ 50 MW x 4hr, Storage
11
Load reduction of 187 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 653 of 1057
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
- 20 40 60 80 100 120
$
p
e
r

k
W
-yr
Megawatts
Demand Response
Summer Programs Evaluated
•Central A/C
•Smart Thermostats-Cooling
•Thermal Energy Storage
12
25 MW Load Control is also included, but not shown as its prices would likely be negotiated
Cost Effective Start Dates
Shown in Red
2025: Variable Peak Pricing
2029: Smart Thermostats
2029: Industrial Load Control
2031: Time of Use
2031: Third Party Contracts
2037: Real Time Pricing
2042: Ancillary Services
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 654 of 1057
2022-2025 Generation Action Plan
•2022-2023 RFP
–Early acquisition to take advantage of federal tax credits
–Anticipate 300 MW Wind PPA (84 aMW)
•100 MW in MT and 200 MW in NW
•locations depend on transmission availability/price
–Solar could replace wind depending on pricing and future price shape forecasts
–Potential for additional resource acquisitions in support of Avista’s clean
electricity goal subject to reliability and affordability considerations.
•2024: Kettle Falls Upgrade
–Incrementally increase Kettle Falls generating capability by installing larger sized
equipment as part of modernization
•2025: 222 MW, Colstrip removed
–Per CETA, Colstrip will not serve Washington loads after 12/31/2025
–The plants future for Idaho customers or wholesale transactions is yet to be
determined
13
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 655 of 1057
2026-2030 Generation Action Plan
•2026: 175 MW, Pumped Hydro
–Assumes low cost, long duration pumped hydro solution is available.
–If resource is not available or price exceeds cost effectiveness tests, siting a
similar sized NG peaker is the next least cost option.
–Sizing will depend on reliability requirements of future power supply system.
•2026: 24 MW, Rathdrum Upgrade
–Increases each unit by 12 MW using a supplemental compression technology or
alternative technology.
•2026: Lancaster PPA expires in October
•2026/27: 200 MW, MT Wind
–Utilizes Colstrip transmission,
–If not available, additional NG and renewables are required.
•2027: 8 MW, Post Falls Upgrade
–Increase generating capability as part of modernization project to maintain FERC
licensing requirements.
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 656 of 1057
2031-2040 Generation Action Plan
•2031: Attempt to renew Mid-C PPA contracts
•2035: Northeast CT retires
•2035: 68 MW Long Lake 2nd Powerhouse
–Seek CETA certification as an eligible resource
•either as 2nd powerhouse and/or reconfiguration of single new powerhouse.
–Begin licensing process
–Optimize the site for cost, capacity, and environmental concerns
–Earlier on-line date may be possible
–NG Peaker and renewable resource would be alternative to this project
•2036: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2038: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2040: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
15
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 657 of 1057
2040-45 Generation Action Plan
•2041: 25 MW x 16 hour Liquid Air Storage (or lowest cost alternative)
•2042-2045: 300 MW Wind PPA Replacement
–Existing PPAs begin to expire
–Repowering is likely necessary
•2042-2045: 300 MW x 4 hour, Lithium-ion (or lowest cost alternative)
•2044: 55 MW, solar w/ 50 MW x 4 hour storage
16
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 658 of 1057
-
200
400
600
800
1,000
1,200
20
2
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2
2
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2
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2
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4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
"Clean" Market Purchases
Clean Generation
Sales Forecast
PRS Comparison to Corporate Clean
Electricity Goal
Goal: Serve customers with 100% cost effective clean electricity
PRS meets 89% of corporate goal by 2027
Notes:1) Prior to 2030, Avista is a net energy seller to the market2) “Clean” market purchases is measured as the regional
generation mix’s CO2 mix compared to a CCCT17
2027 Gap: 1 million MWh
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 659 of 1057
(1.0)
(0.5)
-
0.5
1.0
1.5
2.0
2.5
3.0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
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20
2
6
20
2
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20
4
5
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Net Market Purchases/Sales
New Resources
Current Resources
2018 Actual
Total Net Emissions
Total Net Emissions w/ EV Offsets
PRS: Greenhouse Gas Emissions Forecast
80% to 85% net reduction after 2027
18
Note: Electrification of transportation lowers Avista’s emissions below zero as offsetting
petroleum emissions are lower then Avista’s power related emissions
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 660 of 1057
0
5
10
15
20
25
0
200
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n
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e
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t

(
M
i
l
l
i
o
n
s
)
Rev. Req.
Rev. Req. + 1 Stdev
Rev. Req. 95th Percentile
Avg Rate
PRS: Cost/Rate Forecast
19
System PVRR: $11.83 billion
Today’s Rates: 8.4 c/kWh Idaho and 8.9 c/kWh Washington
2030 Rate: 10.4 cents/kWh
2045 Rate: 14.1 cents/kWh
Note: Assumes non-power supply modelled costs escalate at 2 percent per year
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 661 of 1057
Cost Comparison between PRS and LC
Portfolio w/o CETA
Note: State allocation factors and resource designation will affect these results for each state
In
c
r
e
m
e
n
t
a
l

C
o
s
t
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 662 of 1057
Avoided Costs- Power
Methodology
Energy Prices: Electric market price forecast
Capacity Price: Cost difference between building
resources to meet capacity needs as compared to
not building any new capacity. This cost is divided
by the amount of added capacity and is levelized
and tilted (2% inflation) based on the first capacity
deficit year.
Clean Premium:Difference in total cost of the
PRS and the Least Cost Portfolio to meet capacity.
This cost is divided by the amount of additional
dispatch energy and is levelized and tilted (2%
inflation)starting with the first year of renewable
acquisition.
Clean Premium (w/ Tax Incentive): This shows
the premium associated with renewables assuming
the resource includes either the PTC or ITC.
21
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 663 of 1057
2020 Electric Integrated Resource Plan
Scenario and Sensitivity Analysis
James Gall, IRP Manager
Sixth Technical Advisory Committee Meeting
November 19, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 664 of 1057
Agenda
•Portfolio analysis using the stochastic “expected
case” market forecast
•Portfolio analysis with alternative market prices
(deterministic)-sensitivity analysis
•Electrification scenario
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 665 of 1057
Portfolio Scenarios
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 666 of 1057
Portfolio Scenario Overview
•Uses same electric price forecast, but different resource
assumptions.
•Use optimization to create portfolio, but use different
constraints for each scenario.
•View financial results of each portfolio along with
resource selection.
•No reliability analyses are completed for portfolio
scenarios.
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 667 of 1057
Scenarios
1. Preferred Resource Strategy
2. Least Cost Plan-without CETA
3. Clean Resource Plan: 100% net clean by 2027
4. Rely on energy markets only (no capacity or renewable additions) without CETA
5. 100% net clean by 2027, and no CTs by 2045
6. Least Cost Plan without pumped storage or Long Lake as options
7. Colstrip extended to 2035 without CETA
8. Colstrip extended to 2035 with CETA
9. Least Cost Plan with higher pumped storage cost
10. Least Cost with federal tax credits extended
11. Clean Resource Plan with federal tax credits extended
12. Least Cost Plan with low load growth (flat loads-low economic/population growth)
13. Least Cost Plan with high load growth (high economic/population growth)
14. Least Cost Plan with Lancaster PPA extended five years (financials will not be public)
15. Least Cost Plan with one Colstrip unit operating through 2035
Others: Efficient Frontier portfolio (least risk, 75/25, 50/50, and 25/75)
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 668 of 1057
Load Scenarios
Forecast Winter Peak Low Load Scenario Winter Peak
High Load Scenario Winter Peak Forecast Annual Average
Low Load Scenario Annual Average High Load Scenario Annual Average
Scenarios are based on changing GDP assumptions: The
change effects employment and population growth leading
to load changes.
+152 MW
-136 MW
+96 aMW
-89 aMW
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 669 of 1057
Portfolio
outside of
portfolio
constraints
Efficient Frontier Overview
Ri
s
k
Cost
Least cost-
highest risk
portfolio
Highest
cost-least
risk portfolio
Inefficient
portfolio
7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 670 of 1057
$0
$10
$20
$30
$40
$50
$60
$900 $1,000 $1,100 $1,200 $1,300
20
3
0

P
o
w
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r

S
u
p
p
l
y

C
o
s
t

S
t
d
e
v
2021-45 Levelized Annual Revenue Requirement
Least Risk25/75
50/50
75/25
Least Cost
Efficient Frontier Results
#4: Rely on Energy Markets Only
#2: Least Cost Plan w/o CETA#7:
Colstrip
Extended w/o CETA #1: PRS#10: LC w/
Tax Credits
Extended
#8: Colstrip
Extended w/
CETA
#3 Clean Resource Plan
#11 Clean Resource Plan
w/ Tax Credits
#5 No CTs by 2045
#6 Least Cost w/o P/S or Long Lake
#9: LC w/ higher P/S costs
8 Note: excludes portfolios after #12
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 671 of 1057
2030 Portfolio Resource Selection
9
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 672 of 1057
2040 Portfolio Resource Selection
10
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 673 of 1057
2045 Portfolio Resource Selection
11
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
1. Least Cost Plan/ PRS
2. LCP- w/o CETA
3. Clean Resource Plan (CRP)
4. Rely on Energy Markets Only w/o CETA
5. CRP- No CTs
6. LCP w/o PS/Hydro
7. Colstrip 2035 w/o CETA
8. Colstrip 2035 w/ CETA
9. LCP w/ Higher P/S cost
10. Least Cost w/ federal tax credits…
11. CRP w/ federal tax credits extended
12. LCP Low Economic Growth
13. LCP High Economic Growth
14. LCP w/ Lancaster PPA
Efficient Frontier: Least Risk
Efficient Frontier: 75% Risk/25% Cost
Efficient Frontier: 50% Risk/50% Cost
Efficient Frontier: 25% Risk/75% Cost
Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 674 of 1057
Annual Cost Comparison
12
PVRR (Millions)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 675 of 1057
Rate Comparison
sorted by 2045 rates
13
Cents per kWh Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 676 of 1057
Portfolio Tail Risk
(95th percentile minus expected cost, excludes Social Cost of Carbon)
14
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 677 of 1057
PVRR Risk Adjusted Comparison
Sorted by TailVar without Social Cost of Carbon (SCC)
15
$11.0
$11.5
$12.0
$12.5
$13.0
$13.5
$14.0
$14.5
$15.0
10. LeastCost w/federal taxcreditsextended
12. LCPLowEconomicGrowth
4. Rely onEnergyMarketsOnly w/oCETA
8. Colstrip2035 w/CETA
1. LeastCost Plan/PRS
14. LCP w/LancasterPPA
11. CRPw/ federaltax creditsextended
9. LCP w/Higher P/Scost
7. Colstrip2035 w/oCETA
6. LCP w/oPS/Hydro 2. LCP-w/o CETA 2. LCP-w/o CETA EfficientFrontier:25%Risk/75%Cost
13. LCPHighEconomicGrowth
EfficientFrontier:50%Risk/50%Cost
3. CleanResourcePlan(CRP)
5. CRP-No CTs EfficientFrontier:75%Risk/25%Cost
EfficientFrontier:Least Risk
PV
R
R

(
B
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)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 678 of 1057
Annual Greenhouse Gas Comparison
16
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 679 of 1057
Annualized Greenhouse Gas Emissions
(Levelized using 2.5% discount rate)
17
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 680 of 1057
-$60
-$40
-$20
$0
$20
$40
$60
$80
$100
-0.6 -0.4 -0.2 0.0 0.2 0.4 0.6Ch
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2

(M
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)
Change in Levelized GHG Emissions from Portfolio #2 (Millions)
Cost vs. GHG Emissions
#1-PRS
#3-Clean Resource Plan
#4-Rely on Energy
Markets Only (w/o
CETA)
#5-Clean Resource Plan-No CTs
#6-LCP w/o PS/Hydro #7-Colstrip
2035 w/o CETA
#8-
Colstrip
2035 w/ CETA
#10-LCP w/ Federal Tax
Credits Extended
#9-LCP w/ Higher P/S
Cost
#11-CRP w/ Federal Tax Credits Extended
#12-LCP Low Economic Growth
#14-LCP w/ Lancaster
PPA extended
#13-LCP High
Economic Growth
Implied Carbon Levelized Carbon Prices#1. PRS: $55/metric ton
#3. CRS: $144/metric ton
#5. CRS No CTs: $167/metric ton
18
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 681 of 1057
Scenario Results Summary Table
19 Note: Costs do not include Social Cost of Carbon, but included in optimization
Portfolio
Number Portfolio name
Cost 2021-
2045 (PVRR)
(millions)
Cost 2021-
2030 (PVRR)
(millions)
2030 Risk
(millions)
2030 Rate
(c/kWh)
2045 Rate
(c/KWh)
Levelized
R.R.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 682 of 1057
Resource Acquisition Decision Chart
(Excluding Energy Efficiency)
20

( g gy y)

2020-21 “Clean
Energy” RFP: 221 aMW
2021 Capacity RFP: Up to 345 MW Net Winter Capacity
Colstrip Closure Timing (2026 - 2035)
2020-2025 2026-2030 2030+
Solar/ Wind/ Hydro
Wind Location
Solar Location/Storage
Long Lake Clean Energy Determination
Determine: 2nd Powerhouse vs Combined Powerhouse
Permit and Construct Natural Gas CT or Alternative Technology
Spokane River Licensing Process Long Lake Construction
MT Wind RFP: 58 - 94 aMW
Long Duration Pumped Storage Availability/Price
Existing Regional Capacity
Construction of Natural Gas CT
Long Duration Pumped Storage
Natural Gas CT Permitting & Siting
Hydro Flexibility
Storage Technology (Availability, Price, and Duration)
Existing Natural Gas CT Resources Options
Early Demand Response Acquisition Demand Response Programs (85 MM)
Kettle Falls Upgrade Process (12 MW) (Turbine, generator, ancillary, fuel yard)
2026: Rathdrum CT Upgrade (24 MW)
Post Falls Re-Development (8 MW)
PPA Renegotiation/ Renewable Energy RFPs
Renegotiate Mid-C Hydro PPAs Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 683 of 1057
Idaho Rate Impact for Clean Resource
Strategy
Compares CRS (#3) cost to Idaho’s LC strategy cost, then adjusts
Costs down for REC sales at three different prices
Average Prices: Low-$4/REC, Mid-$6.40/REC, High-$15.40/REC
0%
5%
10%
15%
20%
25%
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
Ra
t
e

C
h
a
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g
e
21
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 684 of 1057
Observations
•Resource acquisitions and decisions are highly dependent on
resource availability to be determined in a RFP.
•Colstrip continuing to 2035 is 0.3% higher cost then operating until
2025, (but rate per kWh is slightly lower due to changes in
conservation). Keeping one unit running does not improve
economics.
•CETA cost caps are likely to be in place closer to 2045.
•Idaho rates will be impacted by REC prices from its sales potential
and how resources are allocated between states.
•Avista’s GHG emissions will lower, but the amount depends on
timing of resources and method for accounting for regional
emissions.
•Low load scenario illustrates resource need if greater energy
efficiency is gained.
22
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 685 of 1057
Market Price Sensitivities
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 686 of 1057
Market Price Sensitivity Analysis
•Use different market prices for each of the 14
portfolios
•Results in 70 sensitivities
•Market sensitivities include:
–Expected Case (deterministic)
–No CETA
–Low natural gas prices
–High natural gas prices
–Social cost of carbon (west-wide dispatch-tax
method)
24
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 687 of 1057
Change in Cost (PVRR)
Sensitivity as Compared to Expected Case
25
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 688 of 1057
Change in Cost (PVRR)
Portfolio as Compared to PRS
26
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 689 of 1057
Change in Levelized GHG Emissions
Sensitivity as Compared to Expected Case
27
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 690 of 1057
Change in Levelized GHG Emissions
Portfolio as Compared to PRS
28
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 691 of 1057
Sensitivity Observations
•Modeling the electric market place with and without CETA shows
only modest changes in costs, but without CETA generally increases
costs as electric market prices are higher.
•Low natural gas prices decrease portfolio costs and high natural gas
prices increase costs, although scenarios with more gas turbines are
more sensitive to gas prices changes-low natural gas prices are
likely to increase Avista’s GHG emissions, while higher prices may
not for Avista, but could for other markets.
•Modeling SCC as a tax increases Avista’s cost, but lowers Avista’s
emissions. The PRS is still a lower cost alternative then other
scenarios in this sensitivity.
29
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 692 of 1057
Electrification Scenario
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 693 of 1057
Electrification Scenario
•Increase electric vehicles
•Increase roof-top solar
•Reduction in end-use natural gas penetration
31
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 694 of 1057
Service Territory Electric Vehicle Forecast
Expected Case
High EV Penetration
32
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 695 of 1057
Electric Vehicle Impact to
Peak & Energy Load Forecast
Energy
Peak
33
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 696 of 1057
Avoided Direct Vehicle Emissions
Expected Case
High EV penetration
34
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 697 of 1057
Customers with Roof-top Solar
Expected Case
High Roof-Top Solar Penetration
35
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 698 of 1057
Roof-Top Solar Load Changes
Energy
Winter Peak
SummerPeak
36
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 699 of 1057
End Use Natural Gas Penetration
NG LDC Electrification
Expected Case
37
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 700 of 1057
Avista’s 2017 Natural Gas Daily Demand
(Core Washington Demand)
1/
1
/
2
0
1
7
1/
1
/
2
0
1
7
1/
1
/
2
0
1
7
1/
1
/
2
0
1
7
2/
1
/
2
0
1
7
2/
1
/
2
0
1
7
2/
1
/
2
0
1
7
3/
1
/
2
0
1
7
3/
1
/
2
0
1
7
3/
1
/
2
0
1
7
4/
1
/
2
0
1
7
4/
1
/
2
0
1
7
4/
1
/
2
0
1
7
4/
1
/
2
0
1
7
5/
1
/
2
0
1
7
5/
1
/
2
0
1
7
5/
1
/
2
0
1
7
6/
1
/
2
0
1
7
6/
1
/
2
0
1
7
6/
1
/
2
0
1
7
6/
1
/
2
0
1
7
7/
1
/
2
0
1
7
7/
1
/
2
0
1
7
7/
1
/
2
0
1
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8/
1
/
2
0
1
7
8/
1
/
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0
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8/
1
/
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9/
1
/
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0
1
7
9/
1
/
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0
1
7
9/
1
/
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0
1
7
9/
1
/
2
0
1
7
10
/
1
/
2
0
1
7
10
/
1
/
2
0
1
7
10
/
1
/
2
0
1
7
11
/
1
/
2
0
1
7
11
/
1
/
2
0
1
7
11
/
1
/
2
0
1
7
11
/
1
/
2
0
1
7
12
/
1
/
2
0
1
7
12
/
1
/
2
0
1
7
12
/
1
/
2
0
1
7
De
k
a
t
h
e
r
m
s
38
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 701 of 1057
NW Electric Utility Load Shape
(All Electric vs. Mix Natural Gas/Electric)
Avista Native Load
Chelan County Public Utility District No. 1
39
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 702 of 1057
Converting Core Natural Gas to Electric
Residential,
61.5%
Commercial,
36.5%
Industrial, 2.0%
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
5 Degrees
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
35 Degrees
Water Heat, 10.0%
Space Heat, 85.0%
Process, 5.0%
5 Degrees
Water Heat, 30.0%
Space Heat, 60.0%
Process, 10.0%
35 Degrees
Annual customer type End use by temperature Efficiency by temperature
Residential Example Residential Example
40
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 703 of 1057
End-Use Natural Gas Load Changes
Energy
Winter Peak
Summer Peak
41
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 704 of 1057
Associated Greenhouse Gas Emissions
From “Former” LDC Natural Gas Customers
42
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 705 of 1057
Total Load Changes
Energy
Winter Peak
Summer Peak
43
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 706 of 1057
2045 Cost Impacts
•Power System requires additional $365 million (25% increase)1
•Assumes an additional 1,080 MW new NG CT peakers, 520 MW
Solar, 1,100 MW storage to meet new system peak load
•Greenhouse gas emissions
•Cost per metric ton: $397 per metric ton for the savings in 2045-
over the 25 years the levelized cost of reduction is $1,942 per metric
ton.
–Does not include changes in Natural Gas LDC existing infrastructure costs
–Does not include load related distribution/transmission investments (this will increase estimate)
–Does not include EV incremental cost over petroleum alternative (this is unknown)
–Does not include home owner equipment and wiring costs (this will increase estimate)
MMT PRS + LDC
NG
Electrification
Scenario Change
Electric utility emissions 0.41 +0.28
Avoided petroleum emissions -0.53 -0.76
LDC natural gas emissions 0.43 -0.43
Total emissions 0.31 -0.91
44 1) Estimate is net of natural gas commodity savings
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 707 of 1057
Observations
•Electric vehicle penetration will have an impact on future resource needs-
how customers use the energy will drive resource decisions.
•Electric vehicles will drive regional emissions lower, but Avista’s emissions
higher.
•Additional rooftop solar makes no material change in winter capacity
planning, but lowers average energy and likely drives rates higher due to
lower kWh sales.
•Electrification of natural gas space and water heating significantly increase
winter load profiles.
•Additional heating electrification will likely result in natural gas peakers due
to duration requirements and may costs result in modest savings of GHG
emissions without significantly lowering storage costs.
•Heating electrification costs significantly exceed the Social Cost of Carbon.
•Externality costs can be significant: transmission, distribution, and direct
home owner and should be considered in policy making.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 708 of 1057
Appendix
Detailed Resource Portfolios
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 709 of 1057
Preferred Resource Strategy
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 175 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2025-2030: 76 MW, Demand Response
2026/27: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2032: 32 MW, Demand Response
2035: 55 MW, Northeast CT retires
2035: 68 MW, Long Lake 2nd
Powerhouse
2036-40: 75 MW x 16 hr, Liquid Air Storage
2037: 1 MW Demand Response
2041-2045
2041: 25 MW x 16 hr, Liquid Air Storage
2042: 2.5 MW, Demand Response
2042-2045: 300 MW Wind PPA Renew
2042-2045: 300 MW x 4 hr, Lithium-ion
2044: 55 MW, Solar w/ 50 MW x 4hr, Storage
47
Load reduction of 187 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 710 of 1057
2) Least Cost Plan
without CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, Pumped Hydro
2026: 257 MW, Lancaster PPA expires
2026-2030: 85 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027: 92 MW, Natural Gas CT
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 84 MW, Natural Gas CT
2038: 25 MW x 16 hr, Liquid Air Storage
2039: 25 MW x 4 hr, Lithium-Ion
2040: 25 MW x 16 hr, Liquid Air Storage
2041-2045
2041-2042: 50 MW x 16 hr, Liquid Air Storage
2043: 55 MW Natural Gas CT
2045: 53 MW x 4 hr, Lithium-ion
2045: 3 MW Demand Response
48
Load reduction of 166 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 711 of 1057
3) Clean Resource Plan
100% net clean by 2030
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2023-2027: 64 MW, Demand Response
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2027-2030: 325 MW, Solar
2029: 20 MW Geothermal
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW Long Lake 2nd
Powerhouse
2032: 21 MW Demand Response
2033-2040: 195 MW Solar w/ 150 MW x 4 hr. Storage
2035: 55 MW, Northeast CT retired
2037: 23 MW Demand Response
2041-2045
2041-2043: 300 MW Wind PPA Renew
2042: 25 MW x 16 hr Liquid Air Storage
2043-45: 225 MW x 4 hr, Lithium-ion
2040-45: 70 MW Solar w/ 50 MW x 4 hr. Storage
2045: 3 MW, Demand Response
49
Load reduction of 213 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 712 of 1057
4) Rely on Energy Markets Only
(no capacity or renewable additions)
2021-2030
2026: 222 MW, Colstrip removed
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2031-2040
2035: 55 MW, Northeast CT retired 2041-2045
50
Load reduction of 127 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 713 of 1057
5) 100% Net Clean by 2027
and No CTs by 2045
2021-2030
2022: 150 MW, Solar
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 150 MW, Pumped Hydro
2026: 200 MW, MT Wind
2026: 257 MW, Lancaster PPA expires
2025-2027: 64 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2027-2028: 275 MW, NW Solar
2030: 50 MW, NW Solar
2029: 20 MW, Geothermal
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd
Powerhouse
2031: 21 MW, Demand Response
2033: 55 MW, NW Solar
2035: 55 MW, Northeast CT retired
2036-2040: 140 MW Solar w/ 125 MW x 4 hr, Storage
2037: 23 MW, Demand Response
2040: 200 MW x 16 hr Liquid Air Storage
2040: 75 MW Pumped Hydro
2035: 154 MW, Rathdrum CTs removed
2041-2045
2041-2043: 300 MW Wind PPA Renew
2043: 9 MW, Kettle Falls CT removed
2043: 25 MW, Boulder Park removed
2042-2044: 125 MW x 16 hr Liquid Air Storage
2043-45: 28 MW x 4 hr, Lithium-ion
2045: 302 MW, Coyote Springs 2 removed
2045: 130 MW Solar w/ 75 MW x 4 hr, Storage
2045: 225 MW Pumped Hydro
2045: 100 MW Small Nuclear
2045: 50 MW Biomass
51
Load reduction of 214 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 714 of 1057
6) Least Cost Plan
w/o pumped storage or Long Lake, meeting CETA
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 245 MW, Natural Gas CT
2027: 55 MW, Demand Response
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-2035: 53 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 200 MW, MT Wind
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW Wind PPA
Renew
2041: 25 MW x 16 hr, Liquid Air Storage
2044-2045: 150 MW x 4 hr, Lithium-ion
2044: 25 MW x 16 hr Liquid Air Storage
2045: 100 MW Solar w/ 100 MW x 4 hr, Storage
2045: 20 MW, Geothermal
52
Load reduction of 177 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 715 of 1057
7) Colstrip Extended to 2035 w/o CETA
2021-2030
2022: 100 MW, MT Wind
2026: 12 MW, Kettle Falls Upgrade
2026: 200 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 92 MW, Natural Gas CT
2027: 8 MW, Post Falls Upgrade
2028-2030: 85 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035: 84 MW, Natural Gas CT
2038: 25 MW x 16 hr Liquid Air Storage
2039: 25 MW x 4 hr, Lithium-ion
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042: 25 MW x 16 hr Liquid Air Storage
2043: 55 MW, Natural Gas CT
2045: 53 MW x 4 hr, Lithium-ion
2045: 3 MW, Demand Response
53
Load reduction of 166 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 716 of 1057
8) Colstrip Extended to 2035 w/ CETA
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 250 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2028: 64 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-2032: 45 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 222 MW, Colstrip removed
2035: 68 MW, Long Lake 2nd
Powerhouse
2036: 200 MW, MT Wind
2041-2045
2042-2045: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2044: 50 MW, Solar w/ 50 MW x 4 hr, Storage
2045: 175 MW x 4 hr Lithium-ion
2045: 3 MW, Demand Response
54
Load reduction of 182 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 717 of 1057
9) Least Cost Plan
w/ 30 Percent higher pumped storage cost
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 75 MW, Pumped Storage
2027: 92 MW, Natural Gas CT
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2027-2030: 76 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031-32: 32 MW, Demand Response
2035: 55 MW, Northeast CT retired
2035: 68 MW, Long Lake 2nd
Powerhouse
2036-2040: 75 MW x 16 hr Liquid Air Storage
2039: 3 MW, Demand Resonse
2041-2045
2041: 25 MW x 16 hr Liquid Air Storage
2042-2045: 300 MW, Wind PPA Renew
2042-45: 303 MW x 4 hr, Lithium-ion
2044: 50 MW Solar w/ 50 MW x 4 hr Storage
55
Load reduction of 189 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 718 of 1057
10) Least Cost Plan
w/ Federal Tax Credits Extended
2021-2030
2022: 100 MW, MT Wind
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2026: 200 MW, MT Wind
2026: 175 MW Pumped Hydro
2026: 283 MW, Lancaster PPA expires
2027: 8 MW, Post Falls Upgrade
2025-2030: 85 MW, Demand Response
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 23 MW, Demand Response
2035: 92 MW, Natural Gas CT
2035: 55 MW, Northeast CT retired
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2042: 300 MW, Wind PPA Renew
2042: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW x 16 hr Liquid Air Storage
2044-2045: 150 MW, Solar w/ 150 MW x 4 hr Storage
2043-2045: 100 MW x 4 hr, Lithium-ion
56
Load reduction of 181 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 719 of 1057
11) Clean Resource Plan
w/ Federal Tax Credits Extended
2021-2030
2022: 100 MW, MT Wind
2022: 150 MW, NW Solar
2023: 200 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2027: 76 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 200 MW, MT Wind
2026: 125 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027-2028: 300 MW, NW Solar
2027: 8 MW, Post Falls Upgrade
2029: 20 MW, Geothermal
2030: 25 MW, Solar
2031-2040
2031: 75 MW, Mid-C PPA Renew
2031: 68 MW, Long Lake 2nd Powerhouse
2033-2035: 32 MW, Demand Response
2035: 55 MW, Northeast CT retired
2033-2040: 250 MW, Solar w/ 225 MW x 4 hr Storage
2041-2045
2041-2042: 300 MW Wind PPA Renew
2043: 25 MW x 16 hr Liquid Air Storage
2042-2045: 225 MW x 4 hr, Lithium-ion
2044: 3 MW, Demand Response
2044-45: 75 MW, Solar w/ 75 MW x 4 hr of Storage
57
Load reduction of 203 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 720 of 1057
12) Least Cost Plan
with Low Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2027: 85 MW, Demand Response
2026: 222 MW, Colstrip removed
2026: 100 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031: 75 MW, Mid-C PPA Renew
2035: 55 MW, Northeast CT retired
2035: 68 MW Long Lake 2nd
Powerhouse
2038: 23 MW Demand Response
2041-2045
2042-2045: 300 MW Wind PPA Renew
2041-2045: 225 MW x 4 hr Storage
2045: 10 MW, Solar
58
Load reduction of 180 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 721 of 1057
13) Least Cost Plan
with High Economic Growth
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2025-2040: 109 MW, Demand Response
2026: 111 MW, Colstrip Unit 3 removed
2026: 250 MW, Pumped Hydro
2026: 24 MW, Rathdrum Upgrade
2026: 257 MW, Lancaster PPA expires
2027: 200 MW, MT Wind
2027: 8 MW, Post Falls Upgrade
2031-2040
2031-2033: 75 MW, Mid-C PPA Renew
2033: 48 MW Natural Gas CT
2035: 68 MW Long Lake 2nd
Powerhouse
2035: 55 MW, Northeast CT retired
2035: 111 MW, Colstrip Unit 4 removed
2037: 48 MW Natural Gas CT
2040: 25 MW x 16 hr Liquid Air Storage
2040: 3 MW, Demand Response
2041-2045
2041-43: 75 MW x 16 hr Liquid Air Storage
2041-2045: 205 MW Solar w/ 200 MW x 4 hr Storage
2042-2045: 300 MW Wind PPA Renew
2043-2044: 200 MW x 4 hr, Lithium-ion
2045: 20 MW, Geothermal
59
Load reduction of 181 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 722 of 1057
14) Least Cost Plan
with Lancaster PPA Extended Five Years
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 222 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2027: 8 MW, Post Falls Upgrade
2030: 30 MW, Demand Response
2031-2040
2031-2032: 75 MW, Mid-C PPA Renew
2031-2035: 78 MW Demand Response
2032: 257 MW, Lancaster PPA expires
2032: 245 MW Natural Gas CT
2035: 55 MW, Northeast CT retired
2035: 200 MW MT Wind
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW, Wind PPA Renew
2042-2044: 150 MW x 4 hr, Lithium-ion
2041: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW x 16 hr Liquid Air Storage
2045: 100 MW, Solar w/ 100 MW x 4 hr Storage
2045: 20 MW, Geothermal
60
Load reduction of 177 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 723 of 1057
15) Least Cost Plan
with Colstrip Unit #4 extended until 2035
2021-2030
2022: 100 MW, MT Wind
2022: 100 MW, NW Wind
2023: 100 MW, NW Wind
2024: 12 MW, Kettle Falls Upgrade
2026: 211 MW, Colstrip removed
2026: 24 MW, Rathdrum Upgrade
2027: 8 MW, Post Falls Upgrade
2030: 30 MW, Demand Response
2031-2040
2031-2032: 75 MW, Mid-C PPA Renew
2031-2035: 78 MW Demand Response
2032: 257 MW, Lancaster PPA expires
2032: 245 MW Natural Gas CT
2035: 55 MW, Northeast CT retired
2035: 200 MW MT Wind
2038: 25 MW x 16 hr Liquid Air Storage
2040: 25 MW x 16 hr Liquid Air Storage
2041-2045
2041-2045: 300 MW, Wind PPA Renew
2042-2044: 150 MW x 4 hr, Lithium-ion
2041: 25 MW x 16 hr Liquid Air Storage
2043: 25 MW x 16 hr Liquid Air Storage
2045: 100 MW, Solar w/ 100 MW x 4 hr Storage
2045: 20 MW, Geothermal
61
Load reduction of 178 aMW due to Energy Efficiency by 2045
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 724 of 1057
2020 Electric IRP
Action Items and IRP Chapter Overview
John Lyons, Ph.D.
Sixth Technical Advisory Committee Meeting
November 19, 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 725 of 1057
Analytical Action Items
•Determine ancillary services costs and benefits for intermittent and
storage resources
•Research emission profiles for different types of resource construction and
manufacturing
•Research the purchase of a third-party electric price forecast and then use
that forecast to run our own dispatch analysis
•CETA issues and rulemaking:
–Low income issues
–Greenhouse gas emissions reporting
–IRP requirements and future reporting
•Consider if IRP needs to be split between states because of timing and
new requirements
•Consider the combination of the electric and natural gas IRPs
•Continued analysis for Colstrip post 2025
2
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 726 of 1057
Resource Action Items
•Determine plan for Long Lake expansion and file with appropriate
agencies concerning if the project meets CETA and licensing issues
•Continued pursuing pumped storage opportunities
•Conduct further transmission network studies for integration of
renewables and contingency CTs
•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
3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 727 of 1057
Other 2020 Action Items
•Other areas of concern or suggestions?
•Please call or email the planning team with any
suggestions or added Action Items
4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 728 of 1057
2020 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 and Demand Response
6.Long-Term Position
7.Transmission & Distribution Planning
8.Generation and Storage Resource Options
9.Market Analysis
10.Preferred Resource Strategy
11.Portfolio Scenarios
12.Action Plan
5
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 729 of 1057
2020 Electric IRP Chapters 1 –3
•Chapter 1: Executive Summary
–High level summary of 2020 IRP and PRS
•Chapter 2: Introduction, IRP Requirements, Stakeholder
Involvement
–TAC overview and rules guiding IRP development
•Chapter 3: Economic and Load Forecast
–Economic conditions in Avista’s service territory
–Avista’s energy and peak forecasts
–Load forecast scenarios
6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 730 of 1057
2020 Electric IRP Chapters Ch. 4 –6
•Chapter 4: Existing Supply Resources
–Avista’s resources
–Contractual resources and obligations
–Avista’s natural gas pipeline overview
•Chapter 5: Energy Efficiency and Demand Response
–Conservation Potential Assessment
–Greenhouse gas offset calculation
–Demand response opportunities
•Chapter 6: Long-Term Position
–Reliability adequacy and reserve margins
–Resource requirements
–7
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 731 of 1057
2020 Electric IRP Chapters Ch. 7 –8
•Chapter 7: 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)
8
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 732 of 1057
2020 Electric IRP Chapters Ch. 8 –9
•Chapter 8: Generation and Storage Resource Options
–New Resource Options
–Avista Plant Upgrades
•Chapter 9: Market Analysis
–Marketplace
–Federal and State Environmental Policies
–Fuel Price Forecasts
–Market Price Forecast
–Scenario Analysis
9
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 733 of 1057
2020 Electric IRP Chapters Ch. 10 –12
•Chapter 10: Preferred Resource Strategy
–Resource Selection Process
–Preferred Resource Strategy
–Efficient Frontier Analysis
•Chapter 11: Portfolio Scenarios
–Portfolio Scenarios
–Resource Avoided Cost
•Chapter 12: Action Plan
–2017 Action Plan Summary
–2020 Action Plan
10
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 734 of 1057
Remaining 2020 IRP Schedule
•December 18, 2019 –external draft released to TAC
•January 15, 2020 –external draft comments due
•February 28, 2020 –2020 Electric IRP published and available to the
public on Avista’s web site
•Public comments period determined by the Commissions and posted
on their respective web sites
•January 4, 2021 –Draft IRP due for Washington
•April 1, 2021 –File 2021 IRP in Washington
•Aug 31, 2021-File 2021 IRP in Idaho
•TAC schedule for next IRP(s) will be available after we determine if
the IRP needs to be bifurcated between Idaho and Washington
11
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 735 of 1057
Attendees: TAC 6, Tuesday, November 19, 2019 at Avista Headquarters in Spokane, Washington:
John Lyons, Avista; Xin Shane, Avista; Kevin Calhoun, Tyr Energy; Andrew Argetsinger, Tyr Energy; Barry Kathrens, 350.org; Michael Eldred, Idaho Public Utilities Commission; Clint Kalich, Avista; Shelby Herber, Idaho Conservation League; Matt Nykiel, Idaho Conservation League; John Barber, Rockwood Retirement Communities; Dave Van Hersett, Residential Customer; Kirsten Wilson, Washington State DES Energy; Cadie
Olsen, City of Spokane; Jason Thackston, Avista; Rachelle Farnsworth, Idaho Public Utilities Commission; Darrell Soyars, Avista; Collins Sprague, Avista; Terrence Browne, Avista; Garrett Brown, Avista; Grant Forsyth, Avista; Logan Callen, City of Spokane; James Gall, Avista. David Howarth, National Grid; and Jaime Majure, Avista.
Phone Participants:
Jennifer Snyder, Washington UTC; Mike Starrett, Northwest Power and Conservation
Council; Cassie Koerner, Idaho Public Utilities Commission; Amy Wheeless, Northwest
Energy Coalition; Nancy Esteb, Renewable Energy Coalition; and several guest
participants who did not identify themselves.
These notes follow the progression of the meeting. The notes include summaries of the
questions and comments from participants, Avista responses from the presenter are in
italics, and significant points raised by presenters that are not shown on the slides are
also included. Bracketed comments provide additional details and updates.
Introductions and TAC 5 Recap, John Lyons
Matt Nykiel: Will the Idaho and Washington IRPs come back together? Not sure, we will
discuss later today and with both state Commissions.
Cadie Olsen: With the limited availability of people to do economic analysis for CETA,
has that slowed down the work?
John Lyons: Agencies have been working on it [CETA], but there have been staffing
issues. The Washington UTC has a schedule laid out for the next few years for all of the
rulemaking required for CETA.
Review of PRS, James Gall
Matt Nykiel: What is the status of the coal contract?
Jason Thackston: We haven’t signed the contract yet, but are very close and fully
expect it to be signed by the end of the year. [Avista signed a new contract in early
December 2016 for coal through the end of 2024.]
Clint Kalich: Can you clarify the statistic 70% green? 70% of our retail sales for
Washington and Idaho.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 736 of 1057
Matt Nykiel: A similar question as part of the RECs, Avista’s goal is for both states. How
will both be met since selling Idaho RECs to Washington makes it harder to meet the
goal?
Jason Thackston (Slide 3): The purpose of this slide is to show the status of our ability
to comply with the Washington law. That leads into the 100% goal.
Matt Nykiel: How does the model handle situations where it is rainy and windy in
Spokane, but sunny in Montana? Let’s factor in potential at other places, not just here at
the office at Avista. We apply a factor for different locations for availability. 100% on
average or net 100%? We’ll get to that later as well.
James Gall (Slide 5): Solar includes bifacial panels with a single axis tracker. Hydro
includes Long Lake and Post Falls upgrades. We removed the Monroe Street upgrade
from the PRS discussed in the last TAC meeting. Wind includes offshore.
Clint Kalich: For BPA, is that federal hydro? Price is based on a gas plant, but the actual
generation may or may not be federal hydro.
James Gall: Geothermal is not in our region; but is outside our region in southern Idaho,
Nevada (in the last RFP), and in Utah that could get here. Nuclear is another option, but
it is too big for Avista. Modular nuclear of 100 MW is clean and the right size, but will
probably not be commercially available for quite some time. Energy efficiency has been
used by Avista since the 1970s, we have saved over 200 MW on average.
Matt Nykiel: How are wind and solar being modeled? All wind and solar are modeled as
a PPA with different locations. On-system wind and solar have an interconnection cost
and off-system locations have wheeling costs. Each resource type is assigned a peak
credit for contribution to peak loads.
James Gall: Liquid air storage is easy to scale, with long duration storage requiring
more tanks – the same as hydrogen. Flow batteries are both four-hour for vanadium
flow and zinc oxide batteries. Both of these are higher initial cost than lithium ion, but
have a 20-year lifespan instead of 10 years. Regional transmission as a supply
resource is crossed out because we don’t know what will be on the other side of the
transmission line in the future.
Matt Nykiel (Slide 6): Is the social cost of carbon $50 to $60? $80 in 2021. Can you
explain how pipeline upstream emissions are modeled? Losses to move gas on pipeline
and releases from gas wells. We get all of our gas from Canada, mainly Alberta. The
Canadians have a report that shows a little bit less than 1%, times the amount of gas. I
don’t know the name of the document, but it will be in the IRP document.
Slide #7: The lower Montana wind capacity factor is used to account for transmission
losses. We moved to the upper end of pumped hydro storage projects after talking more
with developers. This makes it more reliable like a gas plant. And we added more
planning margin.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 737 of 1057
Dave Van Hersett (Slide 7): How many hours [for pumped hydro]? 40 to 80 hours.
Dave Van Hersett (Slide 10): Is water heating switching from electric to natural gas? No,
it is for heat pump water heaters. We will cover what you are talking about later today.
Slide 11: Modeling versus actual acquisition. We think 100 MW from Montana and 100
MW from the Northwest, but anyone can bid into an RFP and provide the wind power.
Mike Starrett: Is the procedural expectation from the Washington Commission an
acknowledgment? The IRP is acknowledged and then any resources we acquire go into
a future rate case. We show a need to answer the prudency question in a general rate
case. CETA will have a Clean Energy Action Plan.
Jennifer Snyder: Yes, as of right now, it is a rate case prudency question. Clean Energy
Action Plan will be covered later.
Slide 11: Changed pumped hydro up from 150 MW to 175 MW in the PRS and
increased demand response from 2021 to 2030.
Dave Van Hersett: DR is? Demand response, we will get to that later.
Mike Starrett: The presumption is that it goes away, but have you looked at attributes of
Lancaster going forward? Yes, we are showing that later.
Matt Nykiel (Slide 12): Did you model opt in versus opt out? Didn’t model it, but about
50 percent more. We have an estimate of it. Dave, did this answer your question? Yes.
Jason Thackston (Slide 13): 2022/23 acquisitions come online. Issue an RFP spring of
next year. Online by at least 2022, but we will look at later dates in an RFP if they are
better prices. We would rather do an RFP first, then the IRP. This is our best guess
now. Colstrip cannot serve Washington customers after 2025, but could still serve
Idaho’s one third share or get other owners to agree to shut down.
Matt Nykiel: If it [Colstrip] is not cost effective, it is no longer prudent. Colstrip could
operate at minimums or we could sell it, but we could not unilaterally shut it down
ourselves.
John Barber: On the pumped hydro projects, are there others interested? Yes, the
projects are much bigger than we need. There are other parties interested and they
would need even more participants.
Matt Nykiel: With the cost effectiveness caveat, how does that make the business goal
different than business as usual? Other strategies are RECs with CTs [combustion
turbines] to green up the portfolio. We don’t want to jeopardize our customer’s livelihood
for an aspirational goal.
Matt Nykiel: What is that cost effectiveness test?
Jason Thackston: Good question. We are struggling with that too. There was a lot of
squirming in April. We continue to look at the impact of the goal while maintaining
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 738 of 1057
reliability. This goal is aligning ourselves internally. We totally get that from the business
side of things. Gap with how it is marketed and caveats they signal are super important.
Idaho resources are producing for Idaho customers, but are also going to Washington.
There is a signal there so that customers can make an informed decision. This is good
feedback. Thanks.
Dave Van Hersett: Increasing my bills is lowering my reliability.
Jason Thackston: The ideal outcome is 2025-2030. Our CFO always notes that hope is
not a strategy. Rattlesnake Flat is a good example. It is a good alternative even though
we didn’t have a need expressly then.
James Gall: We will issue an RFP in the spring, if more resources come in that would
lower rates; we will get the extra resources.
John Barber: With liquid air, is it taking it down to the Nitrogen or just the Oxygen? We
will need to ask Thomas Dempsey about this. [The liquid air doesn’t separate out the
gases, it uses ordinary air without separating the different gases].
Clint Kalich: Can we retrofit the back end of our gas turbines? We were going down that
path, but last I heard it may not work. So, maybe.
Barry Kathrens: If there is a positive balance, there is more available for [hydro] storage.
We only have two facilities with storage that are already being used. It is already serving
the purpose you are describing.
Jason Thackston: Some hydro can store over seasons, like in Juneau [Alaska]. Building
more generation would force more water over spillways because there will still be the
same amount of water over time.
Matt Nykiel (Slide 17): Back in 2026, Action Plans features for Idaho customers, the use
of Colstrip for customers is undetermined. I’m grappling with it still being used. You are
talking about problems I think about every day. We are always going to run our system
as a whole, but there is a cost allocation issue.
Matt Nykiel: Easy answer from my point of view. There is a balance that has to be
maintained.
Jason Thackston: You may think it is easy, but it is probably more complicated than you
think.
Barry Kathrens: How does a state line affect climate policy? It determines state energy
policy.
Dave Van Hersett (Slide 18): Emissions are less because you are getting rid of gas
burning in my Corvette.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 739 of 1057
Matt Nykiel: Do other utilities model this [reduced car emissions] even though others
made this choice? CETA is working on this for incentives [on electrification of
transportation].
Clint Kalich: There is precedence in energy conservation. Absent that incentive, the
conservation measure may not be installed.
Jason Thackston: Avista has already incented infrastructure for this to enable adoption.
Someone chooses to fly and purchase offsets. Utilities are showing this.
John Lyons: This is the free rider problem. Did you purchase a particular energy
efficient refrigerator for energy savings, the $50 rebate, or because it looks really good
in your kitchen.
Garrett Brown (Slide 19): Is this just residential? It is an average rate for all classes
according.
Matt Nykiel: Does it include the social cost of carbon? It is included in the decision, but
not in the rate. It is averaged all together.
Darrell Soyars: Transmission and distribution – yes, assumes 2 percent growth.
Dave Van Hersett: About one third generation plus distribution plus one-third
transmission on my bill. There are four components with the common costs.
Mike Starrett: When going through rates, it sounds like a composite rate. Can you
characterize it for a single residential customer? No, the best way is to look at it going
bar to bar [on the graph]. We probably need to get more descriptive on that. Is the cost
consistent? This slide is not getting into the scope of how to assign costs to different
customer classes.
Prewritten comments from Dave Van Hersett for his last TAC meeting:
November 19, 2019
Dave’s Reflections on the IRP process 1989 to 2019:
I am 80 now and it is time for me to retire and spend more time chasing grandkids and
my wife.
Quote from Mark Twain: “Twenty years from now you will more disappointed by the
things you didn’t do than by the ones you did do. So, throw off the bow lines. Sail away
from the safe harbor. Catch the trade winds with your sails. Explore. Discover”.
1. Dave’s: background
a. Fifth Generation Spokane Native
b. North Central High School 1957, WSU 1962 Mechanical Engineering,
MBA
c. Veteran, USAF selected Outstanding Procurement Officer USAF 1966
d. Avista residential customer since 1967.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 740 of 1057
e. Power Plant Developer: Coal, Gas Turbines and Renewable Biomass
Fuels (wood, straw & garbage)
f. Commercial and Industrial Conservation Program Business Development
g. Professional Engineer Retired
h. Technical Advisory Committee Member for Avista’s Biannual Integrated
Resource Plan since 1989.

2. Utility is a Three leg stool: customers, capital & utility.
All three are dependent upon each other to be successful. Customers provide a
steady market, investors require a secure and steady return to make an
investment and a staff is the resource to make it happen.
3. Population dictates constant growth at 2% per year
For decades the population growth for the Inland Empire has been about 2% per year.
This constant for long term planning and almost eliminates the risk of losing market or
the customer load for the utility. Thus we have a risk free environment for both the
utility and the investor.
4. Population: 1957, 2019, 2045 : World, USA, WA State, Spokane
5. World pollution contribution & competitive in USA and world
Points to consider:
a. The population growth is the driving factor for all future generation
planning and the operations of the utility to provide services to its
customers. A very low risk profile.
b. Note that the USA is a minority player in the world pollution production.
Even if we reduced our pollution to zero the remaining world countries
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 741 of 1057
would still be producing the majority of pollution. We only have a minor
impact. Countries like China, India and Pakistan each with over a billion
population have the major impact on the pollution to the world
environment. The only result of our zero pollution is to eliminate our
competitive advantage in the world market as a result of our higher
production costs that incorporate significant environmental controls.
c. Nobody is addressing the uncontrolled population explosion on our planet.
The population growth is the root of all demand for resources and
generation of pollution.

6. Utility has Lost objective to serve customers,
I have observed that the utilities have lost their way on their path to serving their
customers. The customers are the utilities life line and reason for existence. In the last
20 years there have been 13 towns in their service area that have lost their main source
of existence, their forest service industries, or sawmills. The utilities have focused on
meeting the concerns of the one percenters, like the Serria Club, instead of serving and
meeting the needs of their customers.
Spokane, Post Falls, Coeur d’Alene, Newport, Sandpoint, Usk, Ione, Kettle Falls,
Northport, Naples, Bonners Ferry, Samuels, Kellogg to name a few.
7. Accommodate and kowtowing to the one percenters : Environmental
groups and greenies.
I have witnessed the domination of the Sierra Club at our IRP meetings. These
representatives are not actual customers of Avista and only bring their message to go
green with no liability on their part for the higher costs we customers will have to pay
and the devastation to our natural resources. Note that less than 1% of the Avista
customers actually participate in the environmental programs offered by Avista.
Examples such as the higher cost Solar and Wind rates for power. Another example is
when the Montana Greenies made a two hour presentation at the IRP meeting to lobby
Avista to withdraw from Colstrip and utilize higher cost wind and solar. None of these
presenters were actual customers of Avista and they came to Avista because they could
not convince their Montana Legislature to terminate Colstrip. I call these Green parties
the 1 percenters (1%) and that I have represent 99% of the Avista customers. These
1% have been accommodated by the Avista IRP staff to a much higher degree than
they actually represent in the Avista customer base.
8. East WA different from Western WA
Eastern Washington population is more conservative than Western WA population.
This is confirmed by the differences of the political representatives. Democrats in
Western WA and Republican majority in Eastern WA. Eastern WA has a lower
population density and the industry base is mining, forest products and farming. We
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 742 of 1057
harvest our natural resources with hard work and longtime husbanding of these natural
resources.
9. UTC to protect customers from utility
In the three legs of the utility business the UTC protects the customers from abuses by
the utilities. The UTC was brought about because of abuses by utilities over the years.
10. UTC to differentiate between East and West WA on implementation of
regulations.
It is my contention that the UTC should take into account the differences between the
East and Western Washington populations in their implementation of the regulations.
We do not need nor do we want to include higher cost Green generation. We want
lower cost and more reliable fossil fuel generation.
11. Loss of forest products industry & towns since 1980’s
Since the 80’s there has been a major loss of industry in the forest products area towns.
13 of these towns in Avista’s service area have lost their sawmills, and the thousands of
jobs they provided for the past 100 or more years. The utility catered to the
environmental movement, (ie. 1%ers) and did not aggressively fight for their continued
existence of the forest products industry and their longtime customer base.
12. Installing High cost wind and solar, no benefits to customers, revenues go
outside of customers.
The utility is bending and accommodating the installation of higher cost wind and solar
generation who’s investment is bringing no real value to the Avista customer base. The
costs to support these green generation resources sends our utility payments to
investors outside of our service area. These green resources require subsidies to make
them somewhat closer to the costs of traditional resources. The cost of green
generation resources increases the overall cost of power to the customers.
13. Opportunity to revise forest products industry and improve forest
production/reduce fire
The May 2019 passage of the CETA act creates a market opportunity for the inland
empire forests and barren lands. If one assumes that the Green Movement and
population growth will continue into the future, we have the barren lands without
population and forests that grow independent of politics that create a business
opportunity for our area. We can develop Green generation resources for sale to other
utilities utilizing our local natural resources and labor.
14. Dark side of Green: cost and eliminates competitive position of PNW and
customers.
The Dark side of Green is the much higher cost and less reliable generation resources
to replace the long time reliable fossil fuel generation resources. An analysis was
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 743 of 1057
prepared by several PNW utilities that concluded that the cost to implement the Green
Resources by 2045 would result in increasing our power cost by three times. This cost
information has not been included in the efforts of the 1%ers. Increasing our power
costs by three times will eliminate our competitiveness of our industries here in the
PNW and the world. This will then result in the further loss of jobs for our population
and a weakening of Avista’s customer base.
15. Cogeneration: small to large: approx. 100 mw.
The Avista load is approximately 1500 MW. The potential for cogeneration is in the
order of 100 MW. This is minor part of the generation resources but is a major
enhancement for the customer. The utility has bypassed the opportunity to create a
customer based generation resource in favor of higher cost wind and solar.
Implementing a customer based generation resources will build a stronger customer
base by proving another revenue source for the customers investing and operating
businesses in Avista’s service area. It is to the advantage of all of the Avista customers
to have a financially sound customer base. Instead the utility has focused on easier
generation resources such as combustion turbines green power to provide for new load
growth. The potential for customer based cogeneration is small percentage of total load
and would require aggressive and cunning promotion by Avista. This is a proven skill of
the Avista staff.
16. Use Renewable biomass generation to firm up wind and solar
We are fortunate to have established forests that can provide a renewable fuel supply
for biomass generation for generations to come. These biomass plants are ideal for
firming up wind and solar generation when the latter are not operational. We owe this to
our customers.
17. Garbage is 50% biomass and renewable: 1 ton per person per year
Garbage has the same heating value as a fuel as forest residues. People generate 1
ton of garbage per year and it is renewable. 50% of the garbage is paper products.
This is the same fuel as renewable forest residues. Garbage as a fuel supply will
generate about 5% of the annual energy needs of the population. In turn using it as a
fuel will eliminate long term creation of unusable lands created by the land fills that
garbage is hauled to. We will need these lands for coming populations.
18. Never understood the Utility customer conservation programs.
One of my pet peeves is the utility conservation programs presented to the IRP
meetings. I have been confused and could not understand the terminology used by the
presenters to justify their projected conservation savings. There seemed to be a double
standard for customer sponsored conservation projects as compared to inhouse
improvements. Remember that the conservation funds come from the customer for the
customer, not for the exclusive benefit of the utility. Example of double standard, Avista
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 744 of 1057
smart meters vs customer information system improvements to reduce energy
consumption.
19. IRP staff very skilled and very good. Just need their efforts directed to
customer enhancement.
The Avista Staff involved with the production of the IRP are very skilled and we are
grateful that they are working on this product. They have to generate a viable 20 year
plan taking into account all of the technical and political variables. This is not an easy
task and they should be acknowledged and complemented for their fine work.
20. Utility legacy for 2020’s: dedicated to bring back forest products industry
utilizing renewable forests, not leaving the forests for a fuel for forest fires.
You have the opportunity to generate and leave a customer oriented legacy of utilizing
our region renewable and natural resources to provide for future energy needs. You
also have the opportunity to bring back the forest products industry to all of the towns in
our region. The objectives of the one percenters is not in our best interests as their
goals promote forest fires, degradation of our renewable forests and loss of jobs for our
customers.
21. Develop Limited potential of customer based generation and utilization of
regions renewable biomass resources. Provides stronger customer base
for all and benefits the utility and the capital providers.
We should be continually working to enhance the viability of our customer base, the
foundation and reason for the existence of the utility. Not kowtowing to the goals and
demands of the 1%. The customer base has demonstrated and stated their desires by
less than 1% participating in the conservation programs to utilize wind and solar
options. Thus 99% want reliable low cost and reliable electric and gas service.
22. What is your legacy going to be? Selling company for bonus or enhancing
your customer base by bringing back forest products industry?
Providing employment for our children of the future or under utilizing our
natural resources?
My vision for your legacy would be to take advantage of the recent CETA legislation
passed by the 1% to bring back our region forest natural resources, bringing back the
jobs and economies of the past, restoring industry in the towns that have lost jobs,
reduce the potential of destructive forest fires, improve the production of the forests.
We know that we will have the need for more jobs every year and you have the
resources and skills to make this happen. The customers need reliable and low cost
energy services. The utility needs a stable and viable customer base. The capitalists
need a reliable low risk market to attract their investments.
In closing it has been my privilege to participate in the IRP Process. I appreciate
and thank you all for your efforts to integrate the demands and objectives of the
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 745 of 1057
many interests wanting a piece of the requirement to provide long term reliable
energy resources for your customers. Keep in mind that customers want low
cost reliable energy supplies, the 1% have social goals in mind. Dave😊😊
Background for Presentation
• Population Growth Establishes Demand for Energy
o Slide #1of Population Growth of Spokane, WA state and World
• Spokane current electric load is 300 Megawatts
• Inland Northwest Resources
o Mining available Mineral Resources
o Forests that grow renewable lumber products and biomass fuels annually
o Garbage
• Utilities Regulated by Washington Utilities and Transportation Commission
(WUTC)
o Requires utilities to provide low cost, reliable electric power to customers
o Monitors compliance with State and Federal regulations.
o Requires a Biannual Integrated Resource Plan providing power for next 20
years.
• Clean Energy Transformation Act (CETA) May 7, 2019
o Commits Washington to an electricity supply free of greenhouses gas
emissions by 2045
o Eliminate Coal and Carbon fuels.
o Require Renewable Energy Resources such as Wind, Solar and Biomass
(Wood)
o When fully implemented electric rates will triple
• Less than 1% of Avista customers purchase higher cost Wind and Solar Electric
rate option.
• Description of Wind Power Plant (Palouse Wind Project: 30 MW)
o Slide #2 comparing Wind Power Plant to Sea First Building.
o Slide #3 with 556 Wind Power Plants located in Spokane
o Spokane Wind Power investment $450,000,000
• Description of Solar Power Plant (Lind Washington Solar Project: 28 MW, 170
acres)
o Slide #4 of 28 Megawatt Wind Solar Project located on 201 acres farm
lands
o Slide #5 of 860,000 solar panels on 2100 Acres in Spokane
o Spokane Solar Power investment $300,000,000
• Description of Avista’s 53 MW Biomass Wood Fueled Project at Kettle Falls
o Slide #6 Avista’s Project Brochure
o 250 Megawatt Biomass Project Investment: $625,000,000
Utilizing Inland Empire Biomass Forest residues for Electric Power Generation
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 746 of 1057
o Provide power when wind does not blow and sun does not shine
o Harvest natures renewable biomass resource rather than letting it rot on
ground
o Reduce fuel for major forest fires
o Bring back vibrant forest products industry, its jobs and towns to Inland
Empire
Biomass Power potential from Inland Empire Forests – 670 Megawatts of
Dispatchable Power
o Hogg fuel steam generation (50 MW) Kettle Falls Power Plant
 Slide #7 Hogged or ground up unused parts of sawmill production
 Slide #8 Ground up logging residues
 Historically burned in wigwam burners at sawmills
o Logging residues (200 MW)
o Thinning stagnant lodgepole stands (200 MW)
 Timber growth from past forest fires, undesirable timber
o Cogeneration at sawmills (90 to 150 MW)
o Wheat Straw (add 10%)
o Municipal Refuse (50 MW)
 1 ton garbage per person per year
 10,000 tons per year per megawatt
 500,000 population of Spokane area
Unique Economic Development Opportunity
o We have large forest areas, dry land farming acreages, low population
o A population that would favor development of its renewable and dispatchable
resources.
o Wind and solar additions to utility systems require a dispatchable resource to
make wind and solar a reliable dispatchable resource.
o Recent rash of forest fires makes a strong case to change the forest
management practices of today to minimize the probability of and size of
forest fires.
o Power generated from a biomass fuel source qualifies as a Renewable
Energy Credit (REC). This is a product that other utilities purchase to offset
generation from non- renewable resources.
Implementation Plan
o Put together a collation of Inland Empire elected officials, US Forest Service
in Colville, area sawmills and Avista to sponsor a program to:
 Produce a reliable Renewable Biomass Fuel Supply
 Reduce likelihood of forest fires
 Improve yield from our region forests
 Bring back the forest products industry to the inland empire
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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o Seek Representative Cathy McMorris Rogers to assist in sponsoring
legislation to make this happen. She is from Kettle Falls and knows the forest
products industry.

Portfolio Scenario Results, James Gall
Matt Nykiel (Slide 5): Is Colstrip operating in portfolios 10 and 11? Yes, those portfolios
assume that CETA doesn’t exist.
Rachelle Farnsworth: Question on reliability for these portfolios. I haven’t validated
them. They are likely close to being reliable, but cannot guarantee it. Numbers 4 and 5
are concerning, but the PRS is reliable. It was not as certain in the last TAC meeting,
but the PRS is reliable now.
Matt Nykiel: Do I understand right that numbers 2 through 15 have not been tested for
reliability? We are more comfortable with the plans that include all of the existing
turbines. Taking reliable units away from a portfolio makes it more unreliable.
Matt Nykiel: Is it a double counting issue?
Clint Kalich (Slide 6): Surplus capacity is benefitting renewables now. It will be different
if we retire resources. As we add more renewables, diversity is a benefit. But, more
renewables need more backstop.
Slide 14: At least some of them with the social cost of carbon. All except for the ones
without CETA. Number 15 shows with the social cost of carbon – risk plus cost.
Dave Van Hersett (Slide 19): Are those are the retail rates that include transmission and
distribution? Correct.
Garrett Brown (Slide 20): On top, what hydro is that? BPA, Mid-C utilities bidding in.
Slide 21: Shows what is the cost of Idaho keeping the RECs for themselves.
Clint Kalich (Slide 21): Are rates backwards? No, losing the opportunity to sell RECs to
Washington or to someone else.
Dave Van Hersett: Haven’t sold them [Idaho share of RECs] yet? Right, this is the cost
of keeping the RECs for Idaho.
Garrett Brown: What happens to the RECs today? Washington buys Idaho’s share of
qualifying hydro RECs from Idaho for I-937. Palouse RECs are sold in the market or to
Washington customers for I-937. Rattlesnake Flat RECs will likely be sold in the early
years.
Matt Nykiel (Slide 19): For portfolios #15, 7 and 8; I assume the party’s shares in costs
for Colstrip remain the same. Yes, we only pay for our share. If, in the highly unlikely
situation where an owner didn’t pay their share, the plant dispatch would be lowered by
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 748 of 1057
their ownership amount. Number 15 shows the scenario where all of the shared costs
are paid for by one unit.
Rachelle Farnsworth (Slide 19): Why is number 2 high risk? There is no renewable
acquisition in that scenario, so there is more variability. So #2 has a fixed price, but also
includes fuel variability.
Matt Nykiel: What are the Idaho risks with portfolio #3 – Avista’s goal? They are the
economic cost of the clean energy goal. So, Avista’s goal should be 100% clean for
Washington only.
Dave Van Hersett (Slide 25): When you say social cost of carbon, is that a tax? This
assumes it is a tax, but we don’t know where it [the money] goes. It is an extra cost of
generation that is borne by customers.
David Howarth (Slide 27): Is this system wide or just in Washington? This is just Avista
emissions, but the wider market prices effect Avista’s dispatch of resources.
Barry Kathrens (Slide 33): What is the service territory population?
Grant Forsyth: About one million electric only with 1.9 cars per household.
Dave Van Hersett (Slide 34): Is that emissions net of generation? Just the petroleum
emissions avoided from more electric cars, we will talk about the rest of the emissions
later.
Grant Forsyth (Slide 37): The households we serve have about 70% natural gas
penetration. Assumes new homes are going all electric or switching from gas to electric
when appliances fail.
Mike Starrett (Slide 38): Assuming that is all powered by electric resistance heat? Yes,
we will get to that in the next slides.
Dave Van Hersett (Slide 44): Is the arithmetic on the right side correct? [Slide fixed
before posting].
Clint Kalich: It looks like the bigger bang for the buck is petroleum. Did you do a one off
calculation on this? No, but will if you direct me to since you’re the boss. No, you’re still
self-directed.
Mike Starrett: I don’t disagree with the analysis; it is fundamentally balanced, wondering
about new homes including air conditioning connection between the supply side and
gas/electric? A lot of our distribution feeders are peaking in the summer because of heat
plus load. Then adding an EV [electric vehicle] is less of an issue in the winter. Air
conditioning is about 7 kW and an electric furnace is about 11-12 kW.
Dave Van Hersett: Will there be an all source RFP for capacity? Yes, capacity and
associated energy.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 749 of 1057
Mike Starrett: Expand on previous opportunity for seasonal or term? Winter focused
need, but we do not limit by season.

2020 IRP Action Items and Overview, John Lyons
No additional notes for this topic.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 750 of 1057

2020 Electric Integrated
Resource Plan

Appendix B – 2020 Electric IRP
Work Plan

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 751 of 1057

Updated Work Plan for Avista’s
2020 Electric Integrated Resource Plan

February 27, 2019

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 752 of 1057
2020 Electric Integrated Resource Planning (IRP) Work Plan

The Company’s updated work plan is submitted in compliance with Order 01 in Docket No. UE-
180738 dated February 15, 2019. Due to the numerous legislative proposals in the States of
Washington, Montana, and Oregon that will have major impacts on the regional electric market,
Avista petitioned the Washington Utilities and Transportation Commission for a temporary
exemption from WAC 480-100-238(4) to change the filing date of its next IRP from August 31,
2019, to February 28, 2020 with an updated work plan to be filed February 28, 2019.

This updated work plan outlines the process Avista will follow to develop its 2020 Electric IRP to
be filed with the Washington and Idaho Commissions by February 28, 2020. 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. Avista held the first TAC meeting for
this IRP on July 25, 2018.

The 2020 IRP process will be similar to those used to produce the previous IRPs. Avista will use
Aurora for electric market price forecasting, resource valuation and for conducting Monte-Carlo
style risk analyses of the electric market place. 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 will utilize its proprietary Avista Decision Support System or ADSS model to
conduct analyses to evaluate reserve products such as ancillary services and intermittent
generation. Avista contracted with Applied Energy Group (AEG) to conduct conservation and
demand response potential studies. Exhibit 1 shows the updated 2020 IRP timeline and the process
to identify the PRS is in Exhibit 2.

Avista intends to use both detailed site-specific and generic resource assumptions in development
of the 2020 IRP. The assumptions combine Avista’s research of similar generating technologies,
engineering studies, and the Northwest Power and Conservation Council’s studies. Avista will rely
on third party and consulting studies for storage resources. Avista will model renewable resources
as power purchase agreements rather than utility-owned assets where it is more economic. This
IRP will study renewable portfolio standards, environmental costs, sustained peaking requirements
and resource adequacy, energy efficiency programs, energy storage and demand response. The
IRP will develop a strategy that meets or exceeds renewable portfolio standards, greenhouse gas
emissions regulations, or other regulations passed by our governing states.

Avista intends to create a PRS based on market and policy assumptions in the expected case based
on the results of pending state energy legislation. The expected case is based on known or likely
drivers affecting the company and energy industry. The IRP will include scenarios to address
alternative futures in the electric market and public policy. TAC meetings help determine the
underlying assumptions used in the expected case, market scenarios and portfolio studies. The IRP
process is very technical and data intensive; public comments are welcome and we encourage
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 753 of 1057
timely input and participation for inclusion into the process so the plan can be submitted according
to the schedule in this Work Plan.

The following topics and meeting times may change depending on the availability of presenters
and requests for additional topics from the TAC members. The timeline and proposed agenda
items for TAC meetings follows:

 TAC 1: Completed on Thursday, July 25, 2018:
o TAC meeting expectations and IRP process overview,
o Review of 2017 IRP acknowledgement & policy statements,
o 2017 IRP action plan update,
o Hydro One merger agreement’s impact on the 2019 IRP,
o Demand and economic forecast, and
o Review the 2019 IRP draft Work Plan.

 TAC 2: Completed on Tuesday, November 27, 2018:
o Modeling process overview, including Aurora and PRiSM,
o Generation options (cost & assumptions),
o Resource adequacy and effective load carrying capability (ELCC) analysis,
o Overview of home heating technologies and efficiency,
o Expected case key assumptions (regional loads, CO2 regulation, etc.), and
o Discuss market and portfolio scenarios.

 TAC 3: Tuesday, April 16, 2019:
o Regional legislative update,
o IRP Transmission planning studies,
o Distribution planning within the IRP,
o Pullman Smart Grid Demonstration Project review,
o Pacific Northwest Pathways to 2050 Study,
o Conservation Potential Assessment (AEG), and
o Demand Response Potential Assessment (AEG).

 TAC 4: Tuesday, August 6, 2019:
o Natural gas price forecast,
o Electric market forecast,
o Energy and peak load forecast,
o Existing resource overview – Colstrip, Lancaster and other resources, and
o Final resource needs assessment.

 TAC 5: Tuesday, October 15, 2019:
o Ancillary services and intermittent generation analysis,
o Energy Imbalance Market analysis,
o Review Preliminary PRS,
o Market scenario results,
o Preliminary Portfolio scenario results,
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 754 of 1057
 TAC 6: Tuesday, November 19, 2019:
o Review of final PRS,
o Market scenario results (continued),
o Final Portfolio scenario results,
o Carbon cost abatement supply curves, and
o 2020 IRP Action Items.

 Draft IRP released to TAC members December 1, 2019. Comments from TAC
members are to be returned to Avista by January 15, 2020. Avista’s IRP team will be
available for conference calls to address comments with individual TAC members or
with the entire group if needed.

2020 Electric IRP Draft Outline

This section provides a draft outline of the major sections in the 2020 Electric IRP. This outline
may change based on IRP study results and input from the TAC.

1. Executive Summary
2. Introduction and Stakeholder Involvement
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 and Demand Response
a. Conservation Potential Assessment
b. Demand Response Opportunities
6. Long-Term Position
a. Reliability Planning and Reserve Margins
b. Resource Requirements
c. Reserves and Flexibility Assessment
7. Transmission Planning
a. Overview of Avista’s Transmission System
b. Future Upgrades and Interconnections (includes project evaluated with DER alternative)
c. Transmission Construction Costs and Integration
d. Merchant Transmission Plan
8. Distribution Planning
a. Overview of Avista’s Distribution System
b. Future Upgrades and Interconnections (includes project evaluated with DER alternative)
9. Generation and Storage Resource Options
a. New Resource Options
b. Avista Plant Upgrades

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 755 of 1057
10. Market Analysis
a. Marketplace
b. Federal and State Environmental Policies
c. Fuel Price Forecasts
d. Market Price Forecast
e. Scenario Analysis
11. Preferred Resource Strategy
a. Resource Selection Process
b. Preferred Resource Strategy
c. Efficient Frontier Analysis
12. Portfolio Scenarios
a. Portfolio Scenarios
b. Resource Avoided Cost
c. Carbon Cost Abatement Supply Curves
13. Action Plan1
a. 2017 Action Plan Summary
b. 2020 Action Plan

1 The Action Plan chapter will become Chapter 14 and a new chapter will be added in the event state legislation
requires additional documentation regarding clean energy.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 756 of 1057

Exhibit 1: 2020 Electric IRP Timeline
Task Target Date
Identify Avista’s supply resource options
(update as needed by July 2019)
Completed
Finalize demand response options & costs Completed
Finalize energy efficiency options April 2019
Transmission & Distribution studies due April 2019
Determine portfolio & market future studies June 2019
Begin Aurora market modeling June 2019
Due date for study requests from TAC members June 15, 2019
Finalize natural gas price forecast July 1, 2019
Finalize datasets/statistics variables for risk studies July 2019
Update and finalize energy & peak forecast July 2019
Finalize PRiSM model assumptions August 2019
Simulation of risk studies “futures” complete September 2019
Simulate market scenarios in Aurora September 2019
Evaluate resource strategies against market futures and scenarios October 2019
Present preliminary study and PRS to TAC November 2019
Writing Tasks
File Updated 2020 IRP Work Plan February 28, 2019
Prepare report and appendix outline June 2019
Prepare text drafts October 2019
Prepare charts and tables October 2019
Internal draft released at Avista October and
November 2019
External draft released to the TAC December 1, 2019
Comments and edits from TAC due January 15, 2020
Final editing and printing February 2020
Final IRP submission to Commissions and TAC February 28, 2020
________________________________________________________________________

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 757 of 1057
Exhibit 2: 2020 Electric IRP Modeling Process

Preferred Resource StrategyAURORA
“Wholesale Electric
Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation Trends
Existing Resources
Avista Load Forecast
Energy,Capacity,& RPSBalances Generation/StorageOptions & Costs
T&DProjects/Costs
Conservation Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity Value
Avoided Costs
Demand Response Measures/Costs
Environmental
Policy
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 758 of 1057

2020 Electric Integrated
Resource Plan

Appendix C – Confidential
Historical Generation Operating
Data

Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 759 of 1057

2020 Electric Integrated
Resource Plan

Appendix D – AEG Conservation
Potential Assessment

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 760 of 1057

Energy Solutions. Delivered. 
AVISTA CONSERVATION POTENTIAL
ASSESSMENT FOR 2021-2040
February 21, 2020
Report prepared for:
AVISTA CORPORATION
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 761 of 1057

This work was performed by
Applied Energy Group, Inc. (AEG)
500 Ygnacio Valley Rd, Suite 250
Walnut Creek, CA 94596
Project Director: K. Kolnowski
Project Manager: K. Walter
Project Team: K. Marrin
B. Bushong
T. Williams

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 762 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 763 of 1057

  | i Applied Energy Group • www.appliedenergygroup.com
CONTENTS
1 INTRODUCTION ............................................................................................ 9
Abbreviations and Acronyms .............................................................................................. 10
2 ANALYSIS APPROACH AND DATA DEVELOPMENT ............................................ 13
Overview 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 .............................................................................................................. 22
Data Sources ........................................................................................................... 22 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 CHARACTERIZATION AND MARKET PROFILES ...................................... 33
Energy Use Summary ............................................................................................................ 33
Residential Sector ................................................................................................................ 34
Commercial Sector .............................................................................................................. 41
Industrial Sector .................................................................................................................... 48
4 BASELINE PROJECTION ................................................................................. 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 CONSERVATION POTENTIAL .......................................................................... 62
Overall 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
Industrial Conservation Potential ............................................................................... 78
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 764 of 1057

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6 DEMAND RESPONSE POTENTIAL ..................................................................... 83
Market Characterization ..................................................................................................... 83
Market segmentation .............................................................................................. 83 Customer Counts by Segment ............................................................................... 84 Forecasts of Winter and Summer Peak Demand................................................... 85 System and Coincident Peak Forecasts by State ................................................. 87 Equipment End Use Saturation ............................................................................... 88
DSM Program Options .......................................................................................................... 90
Program Descriptions .............................................................................................. 90 Program Assumptions and Characteristics ............................................................ 93 Other Cross-cutting Assumptions ......................................................................... 100
DR Potential and Cost Estimates ....................................................................................... 101
Integrated Potential Results ................................................................................. 101 Winter TOU Opt-in Scenario .................................................................................. 101 Cost Results ............................................................................................................ 105
Winter TOU Opt-out Scenario ............................................................................... 106
Cost Results ............................................................................................................ 110
Summer TOU Opt-in Scenario ............................................................................... 111
Cost Results ............................................................................................................ 115
Summer TOU Opt-out Scenario ............................................................................ 116
Cost Results ............................................................................................................ 120
Stand-alone Potential Results ............................................................................... 121
Winter Results ......................................................................................................... 121
Cost Results ............................................................................................................ 125
Summer Results ...................................................................................................... 126
Cost Results ............................................................................................................ 130
A MARKET PROFILES .......................................................................................................... A-1
B MARKET ADOPTION (RAMP) RATES .................................................................................. B-1
C MEASURE DATA .............................................................................................................. C-1
D HB 1444 IMPACT ANALYSIS .............................................................................................D-1

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 765 of 1057

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LIST OF FIGURES
Figure 2-1 LoadMAP Analysis Framework ................................................................................... 14
Figure 2-2 Approach for Conservation Measure Assessment ................................................... 18
Figure 3-1 Sector-Level Electricity Use in Base Year 2017, Washington .................................... 33
Figure 3-2 Sector-Level Electricity Use in Base Year 2017, Idaho .............................................. 34
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................................. 36
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2017), Idaho ... 37
Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017),
Washington ................................................................................................................. 38
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 ................................................................................................................. 42
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Idaho
..................................................................................................................................... 43
Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2017), Washington ..... 44
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 766 of 1057

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Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Idaho ............................................................................................................ 68
Figure 5-8 Residential Technical Achievable Savings Forecast (Cumulative GWh),
Washington ................................................................................................................. 70
Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulative 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 Achievable Savings 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 Savings Forecast (Cumulative GWh),
Washington ................................................................................................................. 81
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho
..................................................................................................................................... 82
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)
..................................................................................................................................... 87
Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter) ... 88
Figure 6-3 Summary of Potential Analysis for Avista (TOU Opt-In Winter Peak MW
@Generator) ............................................................................................................. 102
Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)
................................................................................................................................... 107
Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator) ............ 112
Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator) ........................ 117
Figure 6-7 and Table A-1 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. .................................................................................................................. 121
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator) ............ 122
Figure 6-9 Summary of Summer Potential by Option (MW @Generator) ............................... 127

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 767 of 1057

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LIST OF TABLES
Table 1-1 Explanation of Abbreviations and Acronyms ........................................................... 10
Table 2-1 Overview 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
Table 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
Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho ........................ 73
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 768 of 1057

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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 ................................................................................................ 84
Table 6-2 Baseline C&I Customer Forecast by State and Customer Class .............................. 84
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) ............................................. 85
Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................................... 86
Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................................... 86
Table 6-6 2017 End Use Saturations by Customer Class, Washington...................................... 89
Table 6-7 2017 End Use Saturation by Customer Class, Idaho ................................................. 89
Table 6-8 Class 1 DSM Products Assessed in the Study............................................................. 93
Table 6-9 DSM Steady-State Participation Rates (% of eligible customers) ............................ 95
Table 6-10 DSM Per Participant Impact Assumptions ................................................................. 96
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington)...... 97
Table 6-12 Marketing, Recruitment, Incentive, and Development Costs (Washington) .......... 98
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho) ............... 99
Table 6-14 Marketing, Recruitment, Incentive, and Development Costs (Idaho) ................. 100
Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator) .......... 103
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW
@Generator) ............................................................................................................. 104
Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW
@Generator) ............................................................................................................. 105
Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter) ........................................... 106
Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator) .... 108
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW
@Generator) ............................................................................................................. 109
Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
................................................................................................................................... 110
Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter ........................................ 111
Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator) ....... 113
Table 6-24 Achievable DR Potential by Option for WashingtonTOU Opt-In (Summer MW
@Generator) ............................................................................................................. 114
Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW
@Generator) ............................................................................................................. 115
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In ......................................... 116
Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator) . 118
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW
@Generator) ............................................................................................................. 119
Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW
@Generator) .................................................................................................... 120
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 769 of 1057

  | vii Applied Energy Group • www.appliedenergygroup.com
Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out ..................................... 121
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. .................................................................................................................. 121
Table 6-32 Achievable DR Potential by Option (Winter MW @Generator) ............................. 123
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator) ... 124
Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator) ............. 125
Table 6-35 DR Program Costs and Potential (Winter) ............................................................... 126
Table 6-36 Achievable DR Potential by Option (Summer MW @Generator) .......................... 128
Table 6-37 Achievable DR Potential by Option for Washington (Summer MW @Generator) 129
Table 6-38 Achievable DR Potential by Option for Idaho (Summer MW @Generator) .......... 130
Table 6-39 DR Program Costs and Potential – Summer ............................................................ 131
Table A-1 Washington Residential Single Family Market Profile ................................................... A-2
Table A-2 Washington Residential Multi Family Market Profile ..................................................... A-3
Table A-3 Washington Residential Mobile Home Market Profile .................................................. A-4
Table A-4 Washington Residential Low-Income Market Profile .................................................... A-5
Table A-5 Washington Commercial Large Office Market Profile ................................................. A-6
Table A-6 Washington Commercial Small Office Market Profile .................................................. A-7
Table A-7 Washington Commercial Retail Market Profile ............................................................ A-8
Table A-8 Washington Commercial Restaurant Market Profile .................................................... A-9
Table A-9 Washington Commercial Grocery Market Profile ...................................................... A-10
Table A-10 Washington Commercial Health Market Profile ....................................................... A-11
Table A-11 Washington Commercial College Market Profile ..................................................... A-12
Table A-12 Washington Commercial School Market Profile ....................................................... A-13
Table A-13 Washington Commercial Lodging Market Profile .................................................... A-14
Table A-14 Washington Commercial Warehouse Market Profile ............................................... A-15
Table A-15 Washington Commercial Miscellaneous Market Profile .......................................... A-16
Table A-16 Washington Industrial Market Profile ......................................................................... A-17
Table A-17 Idaho Residential Single Family Market Profile ......................................................... A-18
Table A-18 Idaho Residential Multi Family Market Profile ........................................................... A-19
Table A-19 Idaho Residential Mobile Home Market Profile ........................................................ A-20
Table A-20 Idaho Residential Low-Income Market Profile .......................................................... A-21
Table A-21 Idaho Commercial Large Office Market Profile ....................................................... A-22
Table A-22 Idaho Commercial Small Office Market Profile ........................................................ A-23
Table A-23 Idaho Commercial Retail Market Profile .................................................................. A-24
Table A-24 Idaho Commercial Restaurant Market Profile .......................................................... A-25
Table A-25 Idaho Commercial Grocery Market Profile .............................................................. A-26
Table A-26 Idaho Commercial Health Market Profile ................................................................. A-27
Table A-27 Idaho Commercial College Market Profile .............................................................. A-28
Table A-28 Idaho Commercial School Market Profile ................................................................ A-29
Table A-29 Idaho Commercial Lodging Market Profile .............................................................. A-30
Table A-30 Idaho Commercial Warehouse Market Profile ......................................................... A-31
Table A-31 Idaho Commercial Miscellaneous Market Profile ........................................... A-32
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 770 of 1057

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Table A-32 Idaho Industrial Market Profile .................................................................................. A-33
Table D-1 Impacts of HB 1444 on EE Potential ......................................................................... D-1

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 771 of 1057

| 9 Applied Energy Group • www.appliedenergygroup.com

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 2019 Integrated
Resource Plan (IRP). AEG first performed an electricity CPA for Avista in 2013. We have also performed gas
CPA studies in 2014 and 2016 and an assessment of demand-response potential in 2014. This study updates
Avista’s last electric CPA, which AEG performed in 2017.
Since 2017, additional information became available and there was also a desire for more granularity,
corresponding to increasing sophistication in CPA studies. Therefore, this study provided enhanced
analysis compared to the previous studies.
 The base-year for the analysis was brought forward from 2017 to 2017.
 For the residential sector, the study incorporated Avista’s GenPOP residential saturation survey from
2012. This provided the foundation for the base-year market characterization and energy market
profiles. The Northwest Energy Efficiency Alliance’s (NEEA’s) 2014 Residential Building Stock
Assessment (RBSA) supplemented the GenPOP survey.
 For the commercial sector, analysis was performed for the major building types in the service
territory. Results from the 2017 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 new market transformation
assumptions by the RTF.
 Some measure data from the Seventh Power Plan (Seventh Plan) has been updated to reflect
progress in the last two years.
 The study incorporates updated forecasting assumptions that line up with the most recent Avista
load forecast.
 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 2017 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.
Since economic achievable potential is not included in this CPA, it is not possible to compare achievable
potential results with CPAs prior to 2017. When making comparisons to the previous study we will focus
on Technical Achievable Potential. Compared to the 2017 Study, 10-year technical achievable
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 772 of 1057
Avista Conservation Potential Assessment for 2021-2040| Introduction 
  | 10 Applied Energy Group • www.appliedenergygroup.com
potential has increased to 110.1 aMW from 105.8 aMW. This is a net effect of changes in the measure list,
market transformation, and baseline growth.
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 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 773 of 1057
Avista Conservation Potential Assessment for 2021-2040| Introduction 
  | 11 Applied Energy Group • www.appliedenergygroup.com
Acronym Explanation 
LoadMAP AEG’s Load Management Analysis and Planning™ tool 
LCOE Levelized cost of energy 
MW Megawatt 
NPV Net Present Value 
O&M Operations and Maintenance 
PCT Programmable Communicating Thermostat 
RTU Roof top unit 
TRC Total Resource Cost test 
UEC Unit Energy Consumption  
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 774 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 775 of 1057

| 13 Applied Energy Group • www.appliedenergygroup.com

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, 2017.
2. Develop a baseline projection of energy consumption and peak demand by sector, segment, and
end use for 2017 through 2039.
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 2021-2040.
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 776 of 1057
Avista Conservation Potential Assessment for 2021-2040| Analysis Approach and Data Development 
  | 14 Applied Energy Group • www.appliedenergygroup.com
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 777 of 1057
Avista Conservation Potential Assessment for 2021-2040| Analysis Approach and Data Development 
  | 15 Applied Energy Group • www.appliedenergygroup.com
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.
 Technical 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.
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 Seventh Power Plan, applied to 100% of the applicable market. This case is a
theoretical construct and is provided primarily for planning and informational purposes.
 Technical Achievable Potential refines 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 Seventh 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 at most 85%
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
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/
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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:
 Market 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.
 Saturations define the fraction of homes or square feet with the various technologies. (e.g., homes
with electric space heating).
 UEC (unit energy consumption) or EUI (energy-use index) describes the amount of energy
consumed in 2017 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 Energy Intensity for the residential sector represents the average energy use for the
technology across all homes in 2017. 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 2017.
 Annual Usage 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.
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 Peak Demand 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.
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 2018 through 2040 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 September 2018 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
As this CPA neared its conclusion, the state of Washington passed HB 14443, which establishes new
efficiency rules for several appliance and equipment categories. While the CPA models were not rebuilt to
incorporate these new standards, we did estimate the impacts of these new standards in terms of measure
potential that would be moved into the baseline by this ruling. We present the details of this estimate in
Appendix D.
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

3 https://app.leg.wa.gov/billsummary?BillNumber=1444&Year=2019&initiative=
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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,
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.
 Equipment 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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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.
 Non-equipment measures 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:
1. Building shell (windows, insulation, roofing material)
2. Equipment controls (thermostat, compressor staging and controls)
3. Equipment maintenance (cleaning filters, changing setpoints)
4. Whole-building design (building orientation, advanced new construction designs)
5. Lighting retrofits (assumed to be implemented alongside new LEDs at the equipment’s normal
end of life)
6. Displacement measures (ceiling fan to reduce use of central air conditioners)
7. 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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  2017  n/a 
SEER 14.0 10 to 20 $2,505  1,284 2017 n/a 
SEER 15.0 10 to 20 $2,913  1,199  2017 n/a 
SEER 16.0 10 to 20 $3,321  1,124 2017 n/a 
SEER 18.0 10 to 20 $4,140  999  2017 n/a 
SEER 20.0 10 to 20 $4,955  899 2017 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 applicability4 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 2017 Applicability Lifetime 
(yrs) 
Measure 
Installed Cost 
Energy 
Savings (%) 
Cooling  Insulation ‐ Ceiling Installation 0.00%  4.11%  45  $1,230.69   30.17% 
Cooling Insulation ‐ Wall Cavity Installation 0.00% 5.73% 45 $2,622.52  6.10% 
Cooling  Ducting ‐ Repair and Sealing  22.84%  40.00%  20  $656.94  6.29% 
Cooling Windows ‐ High Efficiency/ENERGY STAR 67.43% 75.00% 45 $3,966.55  9.63% 
Cooling  Thermostat ‐ Connected 4.00%  60.00%  5  $259.00   6.00% 

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/ 
Segments  
Residential  88 176 704 
Commercial 130 260 2,860 
Industrial 111 222 222 
Total Measures Evaluated 329 658 3,786 

4 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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).5 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.
 Technical 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.
 Technical 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 7th 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. For Avista, the project team began with
the ramp rates specified in the Seventh Plan conservation workbooks but modified these to match Avista
program history and service territory specifics. We examined historic program results for the most recent
program years. We then adjusted the 2021 Technical Achievable Potential for these measures to
approximately match the historical results. This provided a starting for 2021 potential that was aligned to
historic results. In future years, the potential factors increased to a maximum of 85%, 55% for emerging
technologies, to model increasing market acceptance and program improvements. For measures within
the Seventh Plan, the Council’s prescribed ramp rates were used. For measures outside the Seventh Plan,
AEG assigned ramp rates comparable to similar measures within the Seventh Plan. The market adoption
rates for each measure appear in Appendix B.
Results of all the potentials analysis are presented in Chapter 5.

5 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.
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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:
 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.
 Economic 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 data: 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:
 Northwest Energy Efficiency Alliance, Residential Building Stock 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
 Northwest Energy Efficiency Alliance, Residential Building Stock Assessment II,
Manufactured Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-
Assessment-II-Manufactured-Homes-Report-2016-2017.pdf
 Northwest Energy Efficiency Alliance, Residential Building Stock Assessment II,
Multifamily Buildings Report 2016-2017, https://neea.org/img/documents/Residential-Building-
Stock-Assessment-II-Multifamily-Homes-Report-2016-2017.pdf
 Northwest Energy Efficiency Alliance, 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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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 Northwest Energy Efficiency Alliance, 2014 Industrial Facilities Site 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.
 Regional 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 .
 Northwest Power and Conservation Council Seventh Plan Conservation Supply Curve
Workbooks. To develop its Seventh Power Plan, the Council used workbooks with detailed
information about measures, available at
https://nwcouncil.app.box.com/v/7thplanconservationdatafiles
 Northwest 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.
 AEG Energy Market 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 Energy Simulation 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.
 AEG’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
 AEG’s Database of Energy Efficiency 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.
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 Recent 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 addition, we used the information about impacts of building codes and
appliance standards from recent reports for the Edison Electric Institute6.
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 Energy 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 2017 AEO.
 Local Weather Data: Weather from NOAA’s National Climatic Data Center for Spokane, WA was
used as the basis for building simulations.
 EPRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we
apply to electricity prices, household income, home size and heating and cooling.
 Database for Energy Efficient Resources (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

6 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
http://www.edisonfoundation.net/iee/Documents/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf.
http://www.edisonfoundation.net/iee/Documents/IEE_FactorsAffectingUSElecConsumption_Final.pdf

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 2017‐2018 
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 2017‐2018 
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 2017‐2018 
DEER 
RTF and NWPCC Seventh Plan data 
Previous studies 
Peak factors Share of technology energy use that occurs 
during the peak hour EnergyShape database 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 789 of 1057
Avista Conservation Potential Assessment for 2021-2040| Analysis Approach and Data Development 
  | 27 Applied Energy Group • www.appliedenergygroup.com
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 2017‐2018 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 2017‐2018 regional forecast 
assumptions7 
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 2017‐2018 

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.

7 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 790 of 1057
Avista Conservation Potential Assessment for 2021-2040| Analysis Approach and Data Development

  | 28 Applied Energy Group • www.appliedenergyroup.com
Table 2-7 Residential Electric Equipment Standards8
End Use Technology 2017 2018 2019 2020 2021   2022 2023 2024 2025 
Cooling Central AC SEER 13.0 
  Room AC EER 10.8 
Cooling/ Air‐Source Heat Pump SEER 13.0 / HSPF 8.2  SEER 14.0 / HSPF 9.0 Heating 
Water Heating Water Heater  EF 0.95   (<=55 gallons) 
  Water Heater  EF 2.0 (Heat Pump Water Heater)   (>55 gallons) 
Lighting General Service Advanced Incandescent  
(~20 lumens/watt) Advanced Incandescent (~45 lumens/watt)  
  Linear Fluorescent T8 (92.5 lm/W lamp)  
Appliances Refrigerator 25% more efficient than the 1997 Final Rule (62 FR 23102)   Freezer 
  Clothes Washer IMEF 1.84 / WF 4.7                   
  Clothes Dryer 3.73 Combined EF                   
Miscellaneous Furnace Fans Conventional ECM                 

8 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 791 of 1057
Avista Conservation Potential Assessment for 2021-2040| Analysis Approach and Data Development

  | 29 Applied Energy Group • www.appliedenergyroup.com
Table 2-8 Commercial Electric Equipment Standards9

End Use Technology 2017 2018 2019 2020 2021 2022 2023 2024 2025
Cooling
Chillers 2007 ASHRAE 90.1
RTUs EER 11.9/11.2
PTAC EER 9.8 EER 11.0
Cooling/
Heating
Heat Pump EER 11.0/ EER 11.4/
COP 3.3 COP 3.3
PTHP EER 10.4/COP 3.1
Ventilation All Constant Air Volume/Variable Air Volume
Lighting
General Service Advanced Incandescent Advanced Incandescent
(~20 lumens/watt) (~45 lumens/watt)
Linear Lighting T8 (82.5 lm/W lamp)
High Bay 51.2 lm/W Metal Halide (55.6 lm/W)
Refrigeration
Walk-In COP 3.2 COP 6.1
Reach-In 32 kWh/sqft
Glass Door 12-28% more efficient than EPACT 2005
Open Display 1,537 kWh/ft 1,453 kWh/ft
Icemaker 6.1 kWh/100 lbs.
Food Service Pre-Rinse 1.6 GPM 1.0 GPM
Motors All Expanded EISA 2007

9 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 792 of 1057
Avista Conservation Potential Assessment for 2021-2040| Analysis Approach and Data Development

  | 30 Applied Energy Group • www.appliedenergyroup.com
Table 2-9 Industrial Electric Equipment Standards10

End Use Technology 2017 2018 2019 2020 2021 2022 2023 2024 2025
Cooling
Chillers 2007 ASHRAE 90.1
RTUs EER 11.9/11.2
PTAC EER 9.8 EER 11.0
Cooling/
Heating
Heat Pump EER 11.0/ EER 11.4/
COP 3.3 COP 3.3
PTHP EER 10.4/COP 3.1
Ventilation All Constant Air Volume/Variable Air Volume
Lighting
General Service Advanced Incandescent Advanced Incandescent
(~20 lumens/watt) (~45 lumens/watt)
Linear Lighting T8 (82.5 lm/W lamp)
High Bay 51.2 lm/W Metal Halide (55.6 lm/W)
Motors All Expanded EISA 2007

10 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 793 of 1057
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| 31 Applied Energy Group • www.appliedenergygroup.com
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 2017‐2018 
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 Seventh Plan 
conservation workbooks 
AEG DEEM 
AEO 2017‐2018 
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 Seventh Plan 
conservation workbooksAEG 
DEEM 
AEO 2017‐2018 
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 Seventh Plan 
conservation workbooks 
AEG DEEM 
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 794 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 32 Applied Energy Group • www.appliedenergygroup.com

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.
 Technical diffusion 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 2016 CPA, we applied the “Retrofit” ramp
rates from the Seventh Power Plan directly as diffusion curves. For technical potential, these rates
summed up to 100% by the 20th year for most measures. Emerging technologies summed to 65% by
the 20th year.
 Adoption rates. 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% for most
measures and 55% for emerging technologies. 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 and 55% for emerging technologies to calculate Technical
Achievable Potential. Adoption rates are presented in Appendix B.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 795 of 1057

| 33 Applied Energy Group • www.appliedenergygroup.com

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, 2017. 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 2017 was 7,954
GWh; 5,311 GWh (WA) and 2,643 GWh (ID). As shown in the tables below, in both states the residential
sector accounts for 49% of the annual energy use, followed by commercial at 41% of the annual energy
use. In terms of winter peak demand, the total system peak in 2017 was 1,649 MW: 1,117 (WA) and 532 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 2017, Washington

Table 3-1 Avista Sector Control Totals (2017), Washington
Sector Annual Electricity % of Winter Peak Demand % of 
Use (GWh) Annual Use (MW) Winter Peak 
Residential 2,607 49% 551 49% 
Commercial 2,200 41% 473 42% 
Industrial 504 9% 93 8% 
Total 5,311 100% 1,117 100% 

Residential
49%
Commercial
41%
Industrial
10%
Annual Use (GWh)
Residential
49%
Commercial
42%
Industrial
9%
Winter Peak (MW)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 796 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 34 Applied Energy Group • www.appliedenergygroup.com
Figure 3-2 Sector-Level Electricity Use in Base Year 2017, Idaho

Table 3-2 Avista Sector Control Totals (2017), Idaho
Sector Annual Electricity % of Winter Peak Demand % of 
Use (GWh) Annual Use (MW) Winter Peak 
Residential 1,250 47% 256 48% 
Commercial 1,027 39% 200 38% 
Industrial 366 14% 76 14% 
Total 2,643 100% 532 100% 
Residential Sector
The total number of households and electricity sales for the service territory were obtained from Avista’s
customer database. In 2017, there were 222,837 households in the state of Washington that used a total
of 2,607 GWh with winter peak demand of 551 MW. Average use per customer (or household) at 11,699
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 2017, there
were 112,001 households that used a total of 1,250 GWh with winter peak demand of 256 MW. Average
use per customer (or household) was 11,158 kWh.
Table 3-3 Residential Sector Control Totals (2017), Washington
Segment Number of 
Customers Electricity Use % of Annual 
Annual 
Use/Customer 
(kWh/HH) 
Winter Peak 
    Single Family 135,485 1,825 70% 13,473 378 
    Multifamily 12,479 101 4% 8,084 27 
    Mobile Home 8,022 97 4% 12,125 19 
    Low Income 66,851 583 22% 8,728 128 
    Total 222,837 2,607 100% 11,699 551 

Residential
49%
Commerci
al
41%
Industrial
10%
Annual Use (GWh)
Residential
49%
Commerci
al
42%
Industrial
9%
Winter Peak (MW)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 797 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 35 Applied Energy Group • www.appliedenergygroup.com
Table 3-4 Residential Sector Control Totals (2017), Idaho
Segment Number of 
Customers 
Electricity 
Use 
% of 
Annual 
Annual Use/Customer 
(kWh/HH) 
Winter 
Peak 
Single Family 68,097 873  70% 12,815  175 
Multifamily 5,488 42 3% 7,681 11 
Mobile Home 5,040 58  5% 11,522  11 
Low Income 33,376 277 22% 8,293 60 
Total 112,001  1,250  100% 11,158  256 

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 13,473 kWh/year (WA) and 12,815 kWh/year (ID).
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 798 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 36 Applied Energy Group • www.appliedenergygroup.com
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2017), Washington

Cooling
5%
Space Heating
35%
Water Heating
13%
Interior Lighting
7%
Exterior Lighting
2%
Appliances
20%
Electronics
6%
Miscellaneous
12%
Annual Use by End Use
Space Heating
49%
Water Heating
14%
Interior Lighting
10%
Exterior Lighting
3%
Appliances
18%
Electronics
2%
Miscellaneous
4%
Winter Peak Demand
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 799 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 37 Applied Energy Group • www.appliedenergygroup.com
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2017), Idaho

Cooling
4%
Space Heating
34%
Water Heating
15%
Interior Lighting
7%
Exterior Lighting
2%
Appliances
21%
Electronics
6%
Miscellaneous
11%
Annual Use by End Use
Cooling
0%
Space Heating
47%
Water Heating
15%
Interior Lighting
10%
Exterior Lighting
3%
Appliances
19%
Electronics
2%Miscellaneous
4%
Winter Peak Demand
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 800 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 38 Applied Energy Group • www.appliedenergygroup.com
Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Washington

Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Idaho

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000
Single Family
Multifamily
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
0 2000 4000 6000 8000 10000 12000 14000
Single Family
Multifamily
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 801 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 39 Applied Energy Group • www.appliedenergygroup.com
Table 3-5 Average Market Profile for the Residential Sector, 2017, Washington
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 30.6%  1,087  333  74.2 
Cooling Room AC 23.5% 401 95 21.1 
Cooling Air‐Source Heat Pump 15.0%  1,178  176  39.3 
Cooling Geothermal Heat Pump 0.7% 1,139 7 1.7 
Cooling Evaporative AC 1.2%  533 6  1.4 
Space Heating Electric Room Heat 25.6% 5,176 1,325 295.2 
Space Heating  Electric Furnace 9.1%  10,447  951  212.0 
Space Heating Air‐Source Heat Pump 15.0% 10,485 1,570 349.9 
Space Heating  Geothermal Heat Pump 0.7%  5,207 34  7.6 
Space Heating Secondary Heating 59.3% 371 220 49.0 
Water Heating  Water Heater <= 55 Gal  53.3%  2,719  1,450  323.2 
Water Heating Water Heater > 55 Gal 3.8% 3,437 131 29.3 
Interior Lighting  General Service Screw‐in  100.0%  633  633  141.2 
Interior Lighting Linear Lighting 100.0% 98 98 21.8 
Interior Lighting  Exempted Screw‐In 100.0% 43 43  9.6 
Exterior Lighting Screw‐in 100.0% 217 217 48.3 
Appliances Clothes Washer 92.0% 79 72  16.1 
Appliances Clothes Dryer 49.5% 735 364 81.0 
Appliances Dishwasher 77.2%  378  292  65.1 
Appliances Refrigerator 94.0% 705 663 147.7 
Appliances Freezer 55.5%  565  313  69.8 
Appliances Second Refrigerator 27.7% 812 225 50.0 
Appliances Stove/Oven 70.2%  440  309  68.9 
Appliances Microwave 94.8% 125 118 26.4 
Electronics Personal Computers 64.9%  161  105  23.3 
Electronics Monitor 129.6% 62 80 17.8 
Electronics Laptops 77.0% 42 33  7.2 
Electronics TVs 178.5% 114 203 45.3 
Electronics Printer/Fax/Copier 73.0% 42 31  6.9 
Electronics Set‐top Boxes/DVRs 145.0% 99 143 31.9 
Electronics Devices and Gadgets 100.0%  108  108  24.0 
Miscellaneous Electric Vehicles 0.1% 4,324 6 1.3 
Miscellaneous  Pool Pump 0.3%  3,500 12  2.7 
Miscellaneous Pool Heater 0.1% 3,517 3 0.7 
Miscellaneous  Hot Tub / Spa 0.4%  2,032 8  1.9 
Miscellaneous Furnace Fan 59.6% 183 109 24.3 
Miscellaneous  Well pump 1.5%  550 8  1.8 
Miscellaneous Miscellaneous 100.0% 1,204 1,204 268.2 
 Total       11,699  2,606.9 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 802 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 40 Applied Energy Group • www.appliedenergygroup.com
Table 3-6 Average Market Profile for the Residential Sector, 2017, Idaho
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 31.1%  1,045  326  36.5 
Cooling Room AC 17.6% 445 78 8.8 
Cooling Air‐Source Heat Pump 8.6%  1,127 97  10.9 
Cooling Geothermal Heat Pump 0.5% 1,140 6 0.7 
Cooling Evaporative AC 1.5%  517 8  0.9 
Space Heating Electric Room Heat 23.5% 6,790 1,596 178.8 
Space Heating  Electric Furnace 11.3%  9,715  1,099  123.1 
Space Heating Air‐Source Heat Pump 8.6% 10,425 901 100.9 
Space Heating  Geothermal Heat Pump 0.5%  5,487 29  3.2 
Space Heating Secondary Heating 48.0% 394 189 21.2 
Water Heating  Water Heater <= 55 Gal  50.4%  2,921  1,472  164.9 
Water Heating Water Heater > 55 Gal 5.1% 3,227 163 18.3 
Interior Lighting  General Service Screw‐in  100.0%  634  634  71.0 
Interior Lighting Linear Lighting 100.0% 98 98 11.0 
Interior Lighting  Exempted Screw‐In 100.0% 43 43  4.8 
Exterior Lighting Screw‐in 100.0% 216 216 24.2 
Appliances Clothes Washer 85.2% 82 69  7.8 
Appliances Clothes Dryer 60.2% 754 453 50.8 
Appliances Dishwasher 77.6%  381  296  33.2 
Appliances Refrigerator 93.2% 703 655 73.4 
Appliances Freezer 52.6%  563  296  33.2 
Appliances Second Refrigerator 27.8% 812 226 25.3 
Appliances Stove/Oven 63.3%  388  246  27.5 
Appliances Microwave 91.2% 126 115 12.9 
Electronics Personal Computers 57.1%  163 93  10.4 
Electronics Monitor 114.1% 62 71 7.9 
Electronics Laptops 79.7% 43 34  3.8 
Electronics TVs 175.6% 115 202 22.6 
Electronics Printer/Fax/Copier 67.1% 43 29  3.2 
Electronics Set‐top Boxes/DVRs 92.8% 100 92 10.4 
Electronics Devices and Gadgets 100.0%  108  108  12.1 
Miscellaneous Electric Vehicles 0.1% 4,324 6 0.7 
Miscellaneous  Pool Pump 0.1%  3,500 5  0.5 
Miscellaneous Pool Heater 0.0% 0 0 0.0 
Miscellaneous  Hot Tub / Spa 0.5%  950 5  0.6 
Miscellaneous Furnace Fan 59.7% 458 274 30.6 
Miscellaneous  Well pump 0.0% 0 0  0.0 
Miscellaneous Miscellaneous 100.0% 928 928 103.9 
 Total      11,158  1,249.7 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 803 of 1057
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  | 41 Applied Energy Group • www.appliedenergygroup.com
Commercial Sector
The total electric energy consumed by commercial customers in Avista’s service area in 2017 was 2,200
GWh (WA) and 1027 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 (2017), Washington
Segment 
Electricity Sales % of Total 
Intensity 
(GWh) Usage 
Small Office 194 9% 16.4 
Large Office 543 25% 19.3 
Restaurant 111 5% 41.8 
Retail 286 13% 13.1 
Grocery 198 9% 46.3 
College 94 4% 13.9 
School 123 6% 8.0 
Health 147 7% 29.9 
Lodging 85 4% 12.7 
Warehouse 104 5% 5.4 
Miscellaneous 316 14% 10.4 
Total 2,200 100% 14.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 804 of 1057
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  | 42 Applied Energy Group • www.appliedenergygroup.com
Table 3-8 Commercial Sector Control Totals (2017), Idaho
Segment Electricity Sales % of Total Intensity (GWh) Usage 
Small Office 91 4% 16.4 
Large Office 253 12% 19.3 
Restaurant 52 2% 41.8 
Retail 134 6% 13.1 
Grocery 92 4% 46.3 
College 44 2% 13.9 
School 57 3% 8.0 
Health 68 3% 29.9 
Lodging 40 2% 12.7 
Warehouse 49 2% 5.4 
Miscellaneous 147 7% 10.4 
Total 1,027 100% 14.5 

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 cooling and
lighting, which comprise almost 48% of annual electricity usage. Winter peak demand is dominated by
heating and lighting.
Figure 3-9 (WA) and Figure 3-10 (ID) presents the electricity usage in GWh by end use and segment. Small
offices, retail, and miscellaneous buildings use the most electricity in the service territory. As far as end
uses, cooling and lighting are the major uses across all segments. Office equipment is concentrated more
in the larger customers.
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Washington

Cooling
15%
Heating
11%
Ventilation
10%
Water Heating
5%
Interior Lighting
25%
Exterior 
Lighting
8%
Refrigeration
7%
Food 
Preparation
3%
Office 
Equipment
8%
Miscellaneous
8%Annual Use by End Use
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 805 of 1057
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  | 43 Applied Energy Group • www.appliedenergygroup.com

Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Idaho

Cooling
4%
Heating
24%
Ventilation
9%
Water Heating
7%
Interior Lighting
28%
Exterior Lighting
3%
Refrigeration
6%
Food Preparation
3%
Office Equipment
8%
Miscellaneous
8%
Winter Peak Demand
Cooling
15%
Heating
11%
Ventilation
10%
Water Heating
5%
Interior Lighting
25%
Exterior 
Lighting
8%
Refrigeration
7%
Food Preparation
3%
Office Equipment
8%
Miscellaneous
8%Annual Use by End Use
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 806 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 44 Applied Energy Group • www.appliedenergygroup.com

Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2017), Washington

Cooling
4%
Heating
24%
Ventilation
9%
Water Heating
7%
Interior Lighting
28%
Exterior Lighting
3%
Refrigeration
6%
Food Preparation
3%
Office Equipment
8%
Miscellaneous
8%
Winter Peak Demand
0
100
200
300
400
500
600
An
n
u
a
l

E
n
e
r
g
y

U
s
e

(
G
W
h
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 807 of 1057
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  | 45 Applied Energy Group • www.appliedenergygroup.com
Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2017), 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
50
100
150
200
250
300
An
n
u
a
l

E
n
e
r
g
y

U
s
e

(
G
W
h
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 808 of 1057
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  | 46 Applied Energy Group • www.appliedenergygroup.com
Table 3-9 Average Electric Market Profile for the Commercial Sector, 2017, Washington
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 8.6% 2.77 0.24  36.3 
Cooling Water‐Cooled Chiller 5.0% 4.48 0.23 34.4 
Cooling RTU 46.4% 2.59 1.20  182.8 
Cooling PTAC 4.3% 2.37 0.10 15.5 
Cooling PTHP 1.7% 1.98 0.03  5.3 
Cooling Evaporative AC 0.1% 1.42 0.00 0.3 
Cooling Air‐Source Heat Pump 8.6% 2.71 0.23  35.6 
Cooling Geothermal Heat Pump 4.3% 1.66 0.07 10.8 
Heating Electric Furnace 3.8% 5.54 0.21  32.2 
Heating Electric Room Heat 15.1% 5.38 0.81 123.9 
Heating PTHP 1.7% 3.60 0.06  9.6 
Heating Air‐Source Heat Pump 8.6% 4.78 0.41 62.9 
Heating Geothermal Heat Pump 4.3% 3.66 0.16  23.8 
Ventilation Ventilation 100.0% 1.42 1.42 216.1 
Water Heating  Water Heater 52.4% 1.29 0.68  103.0 
Interior Lighting General Service Lighting 100.0% 0.31 0.31 47.4 
Interior Lighting  Exempted Lighting 100.0% 0.20 0.20  30.8 
Interior Lighting High‐Bay Lighting 100.0% 1.44 1.44 219.0 
Interior Lighting  Linear Lighting 100.0% 1.67 1.67  253.7 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 16.0 
Exterior Lighting  Area Lighting 100.0% 0.87 0.87  131.6 
Exterior Lighting Linear Lighting 100.0% 0.19 0.19 29.4 
Refrigeration   Walk‐in Refrigerator/Freezer  7.8%  1.66  0.13  19.6 
Refrigeration  Reach‐in Refrigerator/Freezer 15.5% 0.14 0.02 3.4 
Refrigeration   Glass Door Display 33.2% 0.33 0.11  16.8 
Refrigeration  Open Display Case 33.2% 1.98 0.66 99.7 
Refrigeration   Icemaker 32.8% 0.27 0.09  13.6 
Refrigeration  Vending Machine 32.8% 0.16 0.05 8.2 
Food Preparation  Oven 36.1% 0.18 0.06  9.7 
Food Preparation Fryer 35.5% 0.48 0.17 26.1 
Food Preparation  Dishwasher 23.9% 0.51 0.12  18.6 
Food Preparation Hot Food Container 24.9% 0.08 0.02 3.1 
Food Preparation  Steamer 22.3% 0.28 0.06  9.5 
Office Equipment Desktop Computer 100.0% 0.69 0.69 104.8 
Office Equipment  Laptop 99.0% 0.10 0.10  15.1 
Office Equipment Server 88.4% 0.16 0.14 21.6 
Office Equipment  Monitor 100.0% 0.12 0.12  18.5 
Office Equipment Printer/Copier/Fax 100.0% 0.07 0.07 10.8 
Office Equipment  POS Terminal 57.1% 0.04 0.02  3.4 
Miscellaneous Non‐HVAC Motors 58.4% 0.24 0.14 21.0 
Miscellaneous  Pool Pump 8.8% 0.01 0.00  0.2 
Miscellaneous Pool Heater 3.1% 0.02 0.00 0.1 
Miscellaneous  Clothes Washer 11.2% 0.02 0.00  0.3 
Miscellaneous Clothes Dryer 7.2% 0.05 0.00 0.6 
Miscellaneous  Other Miscellaneous  100.0%  1.02  1.02  154.6 
Total       14.46 2,199.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 809 of 1057
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  | 47 Applied Energy Group • www.appliedenergygroup.com
Table 3-10 Average Electric Market Profile for the Commercial Sector, 2017, Idaho
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 8.6% 2.77 0.24  16.9 
Cooling Water‐Cooled Chiller 5.0% 4.48 0.23 16.0 
Cooling RTU 46.4% 2.59 1.20  85.3 
Cooling PTAC 4.3% 2.37 0.10 7.2 
Cooling PTHP 1.7% 1.98 0.03  2.5 
Cooling Evaporative AC 0.1% 1.42 0.00 0.1 
Cooling Air‐Source Heat Pump 8.6% 2.71 0.23  16.6 
Cooling Geothermal Heat Pump 4.3% 1.66 0.07 5.0 
Heating Electric Furnace 3.8% 5.54 0.21  15.0 
Heating Electric Room Heat 15.1% 5.38 0.81 57.8 
Heating PTHP 1.7% 3.60 0.06  4.5 
Heating Air‐Source Heat Pump 8.6% 4.78 0.41 29.4 
Heating Geothermal Heat Pump 4.3% 3.66 0.16  11.1 
Ventilation Ventilation 100.0% 1.42 1.42 100.9 
Water Heating  Water Heater 52.4% 1.29 0.68  48.1 
Interior Lighting General Service Lighting 100.0% 0.31 0.31 22.1 
Interior Lighting  Exempted Lighting 100.0% 0.20 0.20  14.4 
Interior Lighting High‐Bay Lighting 100.0% 1.44 1.44 102.2 
Interior Lighting  Linear Lighting 100.0% 1.67 1.67  118.4 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 7.4 
Exterior Lighting  Area Lighting 100.0% 0.87 0.87  61.4 
Exterior Lighting Linear Lighting 100.0% 0.19 0.19 13.7 
Refrigeration   Walk‐in Refrigerator/Freezer  7.8%  1.66  0.13  9.2 
Refrigeration  Reach‐in Refrigerator/Freezer 15.5% 0.14 0.02 1.6 
Refrigeration   Glass Door Display 33.2% 0.33 0.11  7.9 
Refrigeration  Open Display Case 33.2% 1.98 0.66 46.5 
Refrigeration   Icemaker 32.8% 0.27 0.09  6.3 
Refrigeration  Vending Machine 32.8% 0.16 0.05 3.8 
Food Preparation  Oven 36.1% 0.18 0.06  4.5 
Food Preparation Fryer 35.5% 0.48 0.17 12.2 
Food Preparation  Dishwasher 23.9% 0.51 0.12  8.7 
Food Preparation Hot Food Container 24.9% 0.08 0.02 1.5 
Food Preparation  Steamer 22.3% 0.28 0.06  4.4 
Office Equipment Desktop Computer 100.0% 0.69 0.69 48.9 
Office Equipment  Laptop 99.0% 0.10 0.10  7.0 
Office Equipment Server 88.4% 0.16 0.14 10.1 
Office Equipment  Monitor 100.0% 0.12 0.12  8.6 
Office Equipment Printer/Copier/Fax 100.0% 0.07 0.07 5.1 
Office Equipment  POS Terminal 57.1% 0.04 0.02  1.6 
Miscellaneous Non‐HVAC Motors 58.4% 0.24 0.14 9.8 
Miscellaneous  Pool Pump 8.8% 0.01 0.00  0.1 
Miscellaneous Pool Heater 3.1% 0.02 0.00 0.0 
Miscellaneous  Clothes Washer 11.2% 0.02 0.00  0.1 
Miscellaneous Clothes Dryer 7.2% 0.05 0.00 0.3 
Miscellaneous  Other Miscellaneous  100.0%  1.02  1.02  72.2 
Total       14.46 1,026.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 810 of 1057
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  | 48 Applied Energy Group • www.appliedenergygroup.com
Industrial Sector
The total electricity used in 2017 by Avista’s industrial customers was 870 GWh; 504 GWh (WA) and 366
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 (2017)
State 
Electricity Sales Intensity Winter Peak 
(GWh) (Annual kWh/employee) (MW) 
Washington 504 29,854 93 
Idaho 366 67,257  76 

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 33% 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 19% 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 (2017), All Industries, WA

Cooling
4%
Heating
17%
Ventilation
4%
Interior Lighting
13%
Exterior 
Lighting
Motors
33%
Process
19%
Miscellaneous
7%Annual Use by End Use
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 811 of 1057
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  | 49 Applied Energy Group • www.appliedenergygroup.com

Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All Industries, ID

Cooling
0%
Heating
29%
Ventilation
2%
Interior 
Lighting
12%
Exterior Lighting
1%
Motors
32%
Process
18%
Miscellaneous
6%
Winter Peak Demand
Cooling
4%
Heating
17%
Ventilation
4%
Interior Lighting
13%
Exterior Lighting
3%
Motors
33%
Process
19%
Miscellaneous
7%Annual Use by End Use
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 812 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 50 Applied Energy Group • www.appliedenergygroup.com

Cooling
0%
Heating
29%
Ventilation
2%
Interior 
Lighting
12%
Exterior Lighting
1%
Motors
32%
Process
18%
Miscellaneous
6%Winter Peak Demand
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 813 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 51 Applied Energy Group • www.appliedenergygroup.com
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2017, Washington
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  6,629.79 165.74  2.8 
Cooling Water‐Cooled Chiller 2.5% 6,983.13 174.58 2.9 
Cooling RTU 11.4%  7,389.72 842.74  14.2 
Cooling Air‐Source Heat Pump 1.7% 7,386.34 124.90 2.1 
Cooling Geothermal Heat Pump 0.0%  4,926.69 0.00  0.0 
Heating Electric Furnace 2.3% 32,574.73 747.28 12.6 
Heating Electric Room Heat 12.4%  31,023.55 3,849.55  65.0 
Heating Air‐Source Heat Pump 1.7% 28,604.84 483.71 8.2 
Heating Geothermal Heat Pump 0.0%  19,079.43 0.00  0.0 
Ventilation Ventilation 100.0% 1,077.71 1,077.71 18.2 
Interior Lighting  General Service Lighting  100.0%  206.68  206.68  3.5 
Interior Lighting High‐Bay Lighting 100.0% 3,233.38 3,233.38 54.6 
Interior Lighting  Linear Lighting 100.0%  537.49 537.49  9.1 
Exterior Lighting General Service Lighting 100.0% 38.05 38.05 0.6 
Exterior Lighting  Area Lighting 100.0%  720.88 720.88  12.2 
Exterior Lighting Linear Lighting 100.0% 147.69 147.69 2.5 
Motors Pumps 100.0%  1,899.28 1,899.28  32.1 
Motors Fans & Blowers 100.0% 2,280.92 2,280.92 38.5 
Motors Compressed Air 100.0%  1,844.32 1,844.32  31.2 
Motors Material Handling 100.0% 3,900.92 3,900.92 65.9 
Motors Other Motors 100.0%  65.46 65.46  1.1 
Process Process Heating 100.0% 3,211.52 3,211.52 54.3 
Process Process Cooling 100.0%  843.19 843.19  14.2 
Process Process Refrigeration 100.0% 843.19 843.19 14.2 
Process Process Electrochemical 100.0%  324.59 324.59  5.5 
Process Process Other 100.0% 352.25 352.25 6.0 
Miscellaneous  Miscellaneous 100.0%  1,937.76 1,937.76  32.7 
Total       29,853.79 504.4 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 814 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 52 Applied Energy Group • www.appliedenergygroup.com
Table 3-13 Average Electric Market Profile for the Industrial Sector, 2017, Idaho
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  14,936.14 373.40  2.0 
Cooling Water‐Cooled Chiller 2.5% 15,732.18 393.30 2.1 
Cooling RTU 11.4%  16,648.18 1,898.60  10.3 
Cooling Air‐Source Heat Pump 1.7% 16,640.58 281.39 1.5 
Cooling Geothermal Heat Pump 0.0%  11,099.27 0.00  0.0 
Heating Electric Furnace 2.3% 73,387.09 1,683.53 9.2 
Heating Electric Room Heat 12.4%  69,892.47 8,672.59  47.2 
Heating Air‐Source Heat Pump 1.7% 64,443.40 1,089.73 5.9 
Heating Geothermal Heat Pump 0.0%  42,983.75 0.00  0.0 
Ventilation Ventilation 100.0% 2,427.96 2,427.96 13.2 
Interior Lighting  General Service Lighting  100.0%  465.63  465.63  2.5 
Interior Lighting High‐Bay Lighting 100.0% 7,284.44 7,284.44 39.6 
Interior Lighting  Linear Lighting 100.0%  1,210.90 1,210.90  6.6 
Exterior Lighting General Service Lighting 100.0% 85.72 85.72 0.5 
Exterior Lighting  Area Lighting 100.0%  1,624.05 1,624.05  8.8 
Exterior Lighting Linear Lighting 100.0% 332.72 332.72 1.8 
Motors Pumps 100.0%  4,278.85 4,278.85  23.3 
Motors Fans & Blowers 100.0% 5,138.64 5,138.64 28.0 
Motors Compressed Air 100.0%  4,155.05 4,155.05  22.6 
Motors Material Handling 100.0% 8,788.33 8,788.33 47.8 
Motors Other Motors 100.0%  147.48 147.48  0.8 
Process Process Heating 100.0% 7,235.19 7,235.19 39.4 
Process Process Cooling 100.0%  1,899.62 1,899.62  10.3 
Process Process Refrigeration 100.0% 1,899.62 1,899.62 10.3 
Process Process Electrochemical 100.0%  731.25 731.25  4.0 
Process Process Other 100.0% 793.59 793.59 4.3 
Miscellaneous  Miscellaneous 100.0%  4,365.54 4,365.54  23.8 
Total       67,257.13 366.1 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 815 of 1057

| 53 Applied Energy Group • www.appliedenergygroup.com

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 2017. Annual energy use and summer peak demand values
for 2017 reflect actual weather. In future years, energy use and peak demand reflect normal weather, as
defined by Avista. In the figures below, the shift from actual to normal weather is apparent in the increase
in energy use and peak demand in 2017 for the residential and commercial sectors. This results from the
fact that 2017 was cooler than normal (e.g. more energy was required to heat a home in the Winter of
2017 than in an average year).
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 2,607 GWh in 2017
to 3,254 GWh in 2040, an increase of 25%. Residential use in Idaho increases from 1,250 GWh in 2017 to
1,628 GWh in 2040, an increase of 30%. 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 as the lighting standards from
EISA come into effect. Heating usage increases over the forecast due to going from actual weather in 2017
to normal weather in 2018 and for the rest of the forecast.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 816 of 1057
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Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 
Cooling  138  121  121  122  125  135  ‐2% 
Space Heating 914 816 823 843 882 975 7% 
Water Heating 352  347  345  342  345  366  4% 
Interior Lighting 173 148 137 112 93 88 ‐49% 
Exterior Lighting 48  40  37  31  26  24  ‐51% 
Appliances 525 532 534 541 557 606 16% 
Electronics 156  166  170  180  200  249  59% 
Miscellaneous 301 345 361 411 514 810 169% 
Total 2,607  2,515  2,528  2,581  2,743  3,254  25% 

Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington

0
500
1000
1500
2000
2500
3000
3500
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 817 of 1057
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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 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 
Cooling  58  51  52  53  56  64  10% 
Space Heating 427 386 390 404 430 489 14% 
Water Heating 183  182  181  181  184  199  9% 
Interior Lighting 87 75 70 58 50 50 ‐43% 
Exterior Lighting 24  20  19  16  14  13  ‐46% 
Appliances 264 270 272 278 291 326 24% 
Electronics 70  76  78  83  95  123  75% 
Miscellaneous 136 155 162 184 230 365 167% 
Total 1,250  1,215  1,223  1,256  1,348  1,628  30% 

0
2000
4000
6000
8000
10000
12000
14000
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 818 of 1057
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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 2,200 GWh in 2017, and increasing to 2,531 in 2040, an increase of 15%. In Idaho, annual
electricity use grows from 1,027 GWh in 2017 to 1,159 GWh in 2040, an increase of 13%. The tables and
graphs below present the baseline projection at the end-use level for the commercial sector as a whole.
Usage in lighting is declining throughout the forecast, due largely to the phasing in of codes and standards
0
500
1000
1500
2000
2500
3000
3500
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
0
2000
4000
6000
8000
10000
12000
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 819 of 1057
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such as the EISA 2007 lighting standards. Usage in commercial cooling decreases over the forecast due
to going from actual weather in 2017 to weather-normal in 2018 for the forecast.
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 321  276  275  271  266  267  ‐17% 
Heating 252 245 246 249 256 275 9% 
Ventilation 216  218  219  222  229  248  15% 
Water Heating 103 103 103 104 108 119 15% 
Interior Lighting 551  536  528  515  521  558  1% 
Exterior Lighting 177 176 176 175 177 191 8% 
Refrigeration 161  162  162  164  172  198  23% 
Food Preparation 67 70 71 75 83 101 50% 
Office Equipment 174  179  181  190  208  248  42% 
Miscellaneous 177 193 199 217 251 327 85% 
Total 2,200  2,160  2,162  2,183  2,270  2,531  15% 
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 150  129  129  127  125  127  ‐15% 
Heating 118 115 115 117 120 129 10% 
Ventilation 101  102  102  104  107  116  15% 
Water Heating 48 49 49 50 52 57 19% 
Interior Lighting 257  250  247  241  244  262  2% 
Exterior Lighting 83 82 82 82 83 89 8% 
Refrigeration 75  76  76  77  80  93  23% 
Food Preparation 31 33 33 35 39 47 51% 
Office Equipment 81  84  85  89  97  116  43% 
Miscellaneous 82 90 93 102 109 122 47% 
Total 1,027  1,008  1,010  1,022  1,057  1,159  13% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 820 of 1057
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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
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
0
200
400
600
800
1000
1200
1400
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 821 of 1057
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Industrial Sector Baseline Projections
Annual Use
Annual industrial use increases by 25% 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 increases from 504 GWh in 2017 to 683 GWh in 2040. In
Idaho, annual electricity use increases from 366 GWh in 2017 to 406 GWh in 2040.
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 22  24  24  25  26  28  29% 
Heating 86 93 94 97 102 112 31% 
Ventilation 18  20  20  20  21  23  29% 
Interior Lighting 67 68 67 67 67 71 5% 
Exterior Lighting 15  16  16  16  17  18  19% 
Process 94 103 104 107 112 125 32% 
Motors 169  184  186  191  202  223  32% 
Miscellaneous 33 40 42 48 58 81 148% 
Total 504  548  553  571  605  683  35% 

Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Cooling 16  15  15  15  15  15  ‐8% 
Heating 62 65 65 65 65 65 4% 
Ventilation 13  14  14  14  14  14  6% 
Interior Lighting 49 50 49 47 45 43 ‐12% 
Exterior Lighting 11  12  12  12  11  11  ‐1% 
Process 68 75 75 75 75 75 10% 
Motors 123  134  134  134  134  134  10% 
Miscellaneous 24 29 30 34 39 49 108% 
Total 366  395  395  396  398  406  11% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 822 of 1057
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Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington

Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho

0
100
200
300
400
500
600
700
800
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
0
50
100
150
200
250
300
350
400
450
2017 2020 2023 2026 2029 2032 2035 2038
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Process
Motors
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 823 of 1057
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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 strong growth in electricity use, driven
primarily by customer growth forecasts.
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined
End Use 2017 2021 2022 2025 2030 2040 % Change 
('17‐'40) 

Residential 3,857  3,731  3,751  3,838  4,090  4,882  27% 
Commercial 3,226 3,168 3,171 3,205 3,327 3,690 14% 
Industrial 871  942  948  967  1,004  1,089  25% 
Total 7,953 7,841 7,871 8,009 8,421 9,661 21% 

Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined

‐
2,000
4,000
6,000
8,000
10,000
12,000
2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039
Annual 
Use (GWh)
Industrial
Commercial
Residential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 824 of 1057

| 62 Applied Energy Group • www.appliedenergygroup.com

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.
 Technical Potential reflects the adoption of all conservation measures regardless of cost-
effectiveness. For Washington, first-year savings are 102 GWh, or 2.0% of the baseline projection.
Cumulative savings in 2040 are 1,607 GWh, or 24.5% of the baseline. For Idaho, first-year savings are
51 GWh, or 1.9% of the baseline projection. Cumulative savings in 2040 are 845 GWh, or 26.1% of
the baseline.
 Technical Achievable Potential modifies Technical Potential by accounting for customer
adoption constraints. In Washington, first-year savings are 47 GWh, or 0.9% of the baseline. In 2040,
cumulative technical achievable savings reach 1,272 GWh, or 19.4% of the baseline projection. This
results in average annual savings of 1.0% of the baseline each year. Technical Achievable Potential
reflects 79% of Technical Potential throughout the forecast horizon. For Idaho, first year savings are
24 GWh or 0.9% of the baseline and by 2040 cumulative technical achievable savings reach 673
GWh, or 20.8% of the baseline. This results in average annual savings of 1% of the baseline each
year. Technical Achievable Potential reflects 80% of Technical Potential throughout the forecast
horizon.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 825 of 1057
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Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 5,243 5,268 5,300 5,687 6,572 
Cumulative Savings (GWh)           
Technical Achievable Potential 47  100  158  636  1,272 
Technical Potential 102 203 305 979 1,607 
Cumulative Savings (aMW)          
Technical Achievable Potential 5 11 18 73 145 
Technical Potential 12  23  35  112  183 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.9%  1.9%  3.0%  11.2%  19.4% 
Technical Potential 2.0% 3.9% 5.8% 17.2% 24.5% 

Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 2,628 2,640 2,656 2,834 3,241 
Cumulative Savings (GWh)           
Technical Achievable Potential 24  50  80  328  673 
Technical Potential 51 102 153 502 845 
Cumulative Savings (aMW)          
Technical Achievable Potential 3 6 9 37 77 
Technical Potential 6  12  17  57  96 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.9%  1.9%  3.0%  11.6%  20.8% 
Technical Potential 1.9% 3.9% 5.8% 17.7% 26.1% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 826 of 1057
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  | 64 Applied Energy Group • www.appliedenergygroup.com
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

0%
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2021 2022 2023 2030 2040
% 
o
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2021 2022 2023 2030 2040
% 
o
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Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 827 of 1057
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  | 65 Applied Energy Group • www.appliedenergygroup.com
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

 ‐
 1,000.0
 2,000.0
 3,000.0
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 5,000.0
 6,000.0
 7,000.0
GWh
Baseline Projection
Technical Achievable Potential
Technical Potential
 ‐
 500.0
 1,000.0
 1,500.0
 2,000.0
 2,500.0
 3,000.0
 3,500.0
GWh
Baseline Projection
Technical Achievable Potential
Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 828 of 1057
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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, but by 2040 the
commercial sector potential begins to approach that of residential due to large lost opportunity lighting
equipment and controls measures.
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and ID
  2021 2022 2023 2030 2040 
Cumulative Savings (GWh)  
Residential 31 66 106 461 1,000 
Commercial 33 69 109 414 800 
Industrial 7 15 24 89 145 
Total 71 150 238 965 1,945 

Cumulative Savings (aMW)  
Residential 4 8 12 53 114 
Commercial 4 8 12 47 91 
Industrial 1 2 3 10 17 
Total 8 17 27 110 222 

Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)

‐
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1,000
1,500
2,000
2,500
2021 2022 2023 2030 2040
Ac
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G
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h
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Commercial
Residential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 829 of 1057
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  | 67 Applied Energy Group • www.appliedenergygroup.com
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 the first year, 2021 is 21 GWh,
or 0.8 % of the baseline projection. By 2040, cumulative technical achievable savings are 647 GWh, or
19.5% of the baseline projection. At this level, it represents over 82% of technical potential. For Idaho, first
year technical achievable savings are 10 GWh or 0.8% of the baseline and by 2040 cumulative technical
achievable savings reach 353 GWh, or 21.2% of the baseline. Technical Achievable Potential is 82% of
technical potential in 2040.
Table 5-4 Residential Conservation Potential (Annual Energy), Washington
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 2,528  2,543  2,562  2,783  3,319 
Cumulative Savings (GWh)           
Technical Achievable Potential 21  44  71  305  647 
Technical Potential 48 96 144 475 791 
Cumulative Savings (aMW)          
Technical Achievable Potential 2 5 8 35 74 
Technical Potential 5  11  16  54  90 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.8%  1.7%  2.8%  11.0%  19.5% 
Technical Potential 1.9% 3.8% 5.6% 17.1% 23.8% 

Table 5-5 Residential Conservation Potential (Annual Energy), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 1,223  1,233  1,244  1,370  1,663 
Cumulative Savings (GWh)           
Technical Achievable Potential 10  22  35  157  353 
Technical Potential 24 48 72 246 430 
Cumulative Savings (aMW)          
Technical Achievable Potential 1 2 4 18 40 
Technical Potential 3  5  8  28  49 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.8%  1.8%  2.8%  11.4%  21.2% 
Technical Potential 1.9% 3.9% 5.8% 18.0% 25.9% 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 830 of 1057
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  | 68 Applied Energy Group • www.appliedenergygroup.com
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 annual energy savings in 2022 for
Washington. The top three measures include Ductless Mini Split Heat Pumps (Ducted Forced Air), Water
Heater – Low-Flow Showerheads, and Ductless Mini Split Heat Pump (Zonal). Note that technical
achievable savings do not screen for cost effectiveness and some measures are expected to be screened
out during the IRP process.

0%
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10%
15%
20%
25%
30%
2021 2022 2023 2030 2040
% 
o
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Ba
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Technical Achievable Potential Technical Potential
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2021 2022 2023 2030 2040
% 
o
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Technical Achievable Potential Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 831 of 1057
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Table 5-6 Residential Top Measures in 2019 (Annual Energy, MWh), Washington
Rank Residential Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Ductless Mini Split Heat Pump (Ducted Forced Air)  3,651  8% 
2 Water Heater ‐ Low‐Flow Showerheads 2,834 6% 
3  Ductless Mini Split Heat Pump (Zonal) 2,727  6% 
4 Thermostat ‐ Connected 2,303 5% 
5  Windows ‐ Low‐e Storm Addition 2,011  5% 
6 Building Shell ‐ Infiltration Control 1,976 4% 
7  Ducting ‐ Repair and Sealing 1,832  4% 
8 Windows ‐ Cellular Shades 1,754 4% 
9  Insulation ‐ Floor Installation 1,668  4% 
10 Furnace ‐ Conversion to Air‐Source Heat Pump 1,640 4% 
11  Monitor 1,537  3% 
12 Insulation ‐ Ducting 1,472 3% 
13  Windows ‐ High Efficiency/ENERGY STAR 1,457  3% 
14 General Service Screw‐in 1,374 3% 
15  Insulation ‐ Wall Cavity Installation 1,080  2% 
16 Doors ‐ Storm and Thermal 873 2% 
17  Exterior Lighting ‐ Photosensor Control 802  2% 
18 Insulation ‐ Ceiling Installation 759 2% 
19  Insulation ‐ Radiant Barrier 751  2% 
20 Water Heater ‐ Pipe Insulation 645 1% 
 Total of Top 20 Measures  33,145  75% 
  Total Cumulative Savings 44,428 100% 

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, heat pump water heaters, and LED lighting account for a large portion of potential
over the 20-year study period.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 832 of 1057
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  | 70 Applied Energy Group • www.appliedenergygroup.com
Figure 5-8 Residential Technical Achievable Savings Forecast (Cumulative GWh), Washington

Table 5-7 shows the top residential measures from the perspective of annual energy use in Idaho in 2019.
The top three measures are the same as Washington and include Ductless Mini Split Heat Pumps (Ducted
Forced Air), Water Heater – Low-Flow Showerheads, and Ductless Mini Split Heat Pump (Zonal). Note that
technical achievable savings do not screen for cost effectiveness and some measures are expected to be
screened out during the IRP process.

0
100
200
300
400
500
600
700
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 833 of 1057
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Table 5-7 Residential Top Measures in 2019 (Annual Energy, MWh), Idaho
Rank Residential Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Ductless Mini Split Heat Pump (Ducted Forced Air)  1,934  9% 
2 Ductless Mini Split Heat Pump (Zonal) 1,467 7% 
3  Water Heater ‐ Low‐Flow Showerheads 1,440  7% 
4 Thermostat ‐ Connected 1,086 5% 
5  Windows ‐ Low‐e Storm Addition 921  4% 
6 Building Shell ‐ Infiltration Control 914 4% 
7  Insulation ‐ Floor Installation 893  4% 
8 Furnace ‐ Conversion to Air‐Source Heat Pump 860 4% 
9  Windows ‐ Cellular Shades 829  4% 
10 Insulation ‐ Wall Cavity Installation 725 3% 
11  Ducting ‐ Repair and Sealing 716  3% 
12 Monitor 697 3% 
13  General Service Screw‐in ‐ LEDs 650  3% 
14 Insulation ‐ Ducting 597 3% 
15  Insulation ‐ Ceiling Installation  495  2% 
16 Windows ‐ High Efficiency/ENERGY STAR 420 2% 
17  Doors ‐ Storm and Thermal 395  2% 
18 Exterior Lighting ‐ Photosensor Control 386 2% 
19  Insulation ‐ Foundation 364  2% 
20 Insulation ‐ Radiant Barrier 354 2% 
 Total of Top 20 Measures  16,145  74% 
  Total Cumulative Savings 21,726 100% 

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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 834 of 1057
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  | 72 Applied Energy Group • www.appliedenergygroup.com
Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulative GWh), Idaho

0
50
100
150
200
250
300
350
400
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 835 of 1057
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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
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 2,162  2,166  2,173  2,292  2,562 
Cumulative Savings (GWh)           
Technical Achievable Potential 22  47  73  278  536 
Technical Potential 47 93 139 430 703 
Cumulative Savings (aMW)          
Technical Achievable Potential 3 5 8 32 61 
Technical Potential 5  11  16  49  80 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 1.0%  2.2%  3.4%  12.1%  20.9% 
Technical Potential 2.2% 4.3% 6.4% 18.7% 27.4% 

Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 1,010  1,012  1,016  1,065  1,171 
Cumulative Savings (GWh)           
Technical Achievable Potential 11  22  35  136  264 
Technical Potential 22 44 66 208 344 
Cumulative Savings (aMW)          
Technical Achievable Potential 1 3 4 16 30 
Technical Potential 3  5  8  24  39 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 1.0%  2.2%  3.5%  12.8%  22.6% 
Technical Potential 2.2% 4.4% 6.5% 19.6% 29.4% 
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 22 GWh, or 1.0% of the baseline projection. By
2040, technical achievable savings are 536 GWh, or 20.9% of the baseline projection. Throughout the
forecast horizon, Technical Achievable Potential represents about 76% of technical potential. For Idaho,
first year technical achievable savings are 11 GWh or 1.0% of the baseline and by 2040 cumulative technical
achievable savings reach 264 GWh, or 22.6% of the baseline. Throughout the forecast horizon, Technical
Achievable Potential represents about 77% of technical potential.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 836 of 1057
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  | 74 Applied Energy Group • www.appliedenergygroup.com
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.
0%
5%
10%
15%
20%
25%
30%
35%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
0%
5%
10%
15%
20%
25%
30%
35%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 837 of 1057
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  | 75 Applied Energy Group • www.appliedenergygroup.com
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.
Table 5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Linear Lighting ‐ LEDs 3,852  8% 
2 High‐Bay Lighting ‐ LEDs 2,674 6% 
3  Space Heating ‐ Heat Recovery Ventilator 2,252  5% 
4 Refrigeration ‐ Evaporative Condenser 2,181 5% 
5  Area Lighting ‐ LEDs 1,908  4% 
6 Chiller ‐ Variable Flow Chilled Water Pump 1,714 4% 
7  Refrigeration ‐ Variable Speed Compressor 1,678  4% 
8 Refrigeration ‐ Replace Single‐Compressor with Subcooled Multiplex 1,607 3% 
9  HVAC ‐ Dedicated Outdoor Air System (DOAS) 1,434  3% 
10 Exterior Lighting ‐ Bi‐Level Parking Garage Fixture 1,407 3% 
11  Exterior Lighting ‐ Photovoltaic Installation  1,385  3% 
12 Retrocommissioning 1,322 3% 
13  Destratification Fans (HVLS) 1,207  3% 
14 Refrigeration ‐ High Efficiency Compressor 1,126 2% 
15  Water Heater ‐ Solar System 1,090  2% 
16 Refrigeration ‐ ECM Compressor Head Fan Motor 984 2% 
17  Interior Lighting ‐ Networked Fixture Controls 922  2% 
18 Office Equipment ‐ Advanced Power Strips 903 2% 
19  Exterior Lighting ‐ Enhanced Controls 691  1% 
20 Water Heater ‐ Pipe Insulation 664 1% 
 Total of Top 20 Measures  31,001  66% 
  Total Cumulative Savings 46,666 100% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 838 of 1057
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Figure 5-12 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Washington

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500
600
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 839 of 1057
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  | 77 Applied Energy Group • www.appliedenergygroup.com
Table 5-11 Commercial Top Measures in 2019 (Annual Energy, MWh), Idaho
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Linear Lighting – LEDs 1,809  8% 
2 High‐Bay Lighting ‐ LEDs 1,256 6% 
3  Space Heating ‐ Heat Recovery Ventilator 1,165  5% 
4 Refrigeration ‐ Evaporative Condenser 1,018 5% 
5  Area Lighting ‐ LEDs 896  4% 
6 Chiller ‐ Variable Flow Chilled Water Pump 812 4% 
7  Refrigeration ‐ Variable Speed Compressor 791  4% 
8 Refrigeration ‐ Replace Single‐Compressor with Subcooled Multiplex 750 3% 
9  HVAC ‐ Dedicated Outdoor Air System (DOAS) 668  3% 
10 Retrocommissioning 659 3% 
11  Exterior Lighting ‐ Bi‐Level Parking Garage Fixture  658  3% 
12 Exterior Lighting ‐ Photovoltaic Installation 647 3% 
13  Destratification Fans (HVLS) 563  3% 
14 Refrigeration ‐ High Efficiency Compressor 530 2% 
15  Water Heater ‐ Solar System 517  2% 
16 Refrigeration ‐ ECM Compressor Head Fan Motor 456 2% 
17  Interior Lighting ‐ Networked Fixture Controls 432  2% 
18 Office Equipment ‐ Advanced Power Strips 421 2% 
19  Exterior Lighting ‐ Enhanced Controls 323  1% 
20 Water Heater ‐ Pipe Insulation 315 1% 
 Total of Top 20 Measures 14,686  66% 
  Total Cumulative Savings 22,325 100% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 840 of 1057
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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, 2021, are 4
GWh, or 0.8% of the baseline projection. In 2040, savings reach 89 GWh, or 12.9% of the baseline
projection. For Idaho, technical achievable savings in the first year, 2021, are 3 GWh, or 0.7% of the baseline
projection. In 2040, savings reach 56 GWh, or 13.7% of the baseline projection.
Table 5-12 Industrial Conservation Potential (Annual Energy), WA
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 553  559  565  612  691 
Cumulative Savings (GWh)           
Technical Achievable Potential 4  9  14  54  89 
Technical Potential 7 15 22 74 114 
Cumulative Savings (aMW)          
Technical Achievable Potential 0 1 2 6 10 
Technical Potential 1  2  3  8  13 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.8%  1.6%  2.5%  8.8%  12.9% 
Technical Potential 1.3% 2.6% 3.9% 12.2% 16.4% 
0
50
100
150
200
250
300
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 841 of 1057
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  | 79 Applied Energy Group • www.appliedenergygroup.com

Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho
  2021 2022 2023 2030 2040 
Baseline projection (GWh) 395  395  395  399  407 
Cumulative Savings (GWh)           
Technical Achievable Potential 3  6  10  35  56 
Technical Potential 5 10 15 48 71 
Cumulative Savings (aMW)          
Technical Achievable Potential 0 1 1 4 6 
Technical Potential 1  1  2  5  8 
Cumulative Savings as a % of Baseline           
Technical Achievable Potential 0.7%  1.6%  2.4%  8.9%  13.7% 
Technical Potential 1.2% 2.4% 3.7% 12.0% 17.4% 

Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy),
Washington

0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 842 of 1057
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  | 80 Applied Energy Group • www.appliedenergygroup.com
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 the instillation of destratification fans (HVLS). The
measure with the second highest savings is the upgrade of compressed air equipment. Compressed air
leak management program 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%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
2021 2022 2023 2030 2040
% of 
Baseline
Technical Achievable Potential Technical Potential
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 843 of 1057
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  | 81 Applied Energy Group • www.appliedenergygroup.com
Table 5-14 Industrial Top Measures in 2019 (Annual Energy, GWh), Washington
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Destratification Fans (HVLS) 1,263  14% 
2 Compressed Air ‐ Equipment Upgrade 746 8% 
3  Compressed Air ‐ Leak Management Program 728  8% 
4 High‐Bay Lighting ‐ LEDs 673 8% 
5  Pumping System ‐ Equipment Upgrade 372  4% 
6 Fan System ‐ Equipment Upgrade 246 3% 
7  Paper: Premium Control Large Material  221  2% 
8 Material Handling ‐ Variable Speed Drive 216 2% 
9  Retrocommissioning 213  2% 
10 Kraft: Efficient Agitator 203 2% 
11  Fan System ‐ Variable Speed Drive 192  2% 
12 Area Lighting 184 2% 
13  Compressed Air ‐ Outside Air Intake 181  2% 
14 Paper: Efficient Pulp Screen  178 2% 
15  Exterior Lighting ‐ Enhanced Controls 178  2% 
16 Interior Lighting ‐ Networked Fixture Controls 173 2% 
17  Linear Lighting ‐ LEDs 169  2% 
18 Compressed Air ‐ End Use Optimization 145 2% 
19  Thermostat ‐ Wi‐Fi/Interactive  140  2% 
20 Motors ‐ Synchronous Belts 137 2% 
 Total of Top 20 Measures  6,560  74% 
  Total Cumulative Savings 8,883 100% 

Figure 5-16 Industrial Technical Achievable Savings Forecast (Cumulative GWh), Washington

0
10
20
30
40
50
60
70
80
90
100
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 844 of 1057
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  | 82 Applied Energy Group • www.appliedenergygroup.com
Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho
Rank Commercial Measure 
2022 Cumulative  
Energy Savings % of 
(MWh)  Total  
1  Destratification Fans (HVLS) 863  14% 
2 Compressed Air ‐ Equipment Upgrade 537 9% 
3  Compressed Air ‐ Leak Management Program 524  9% 
4 High‐Bay Lighting 413 7% 
5  Pumping System ‐ Equipment Upgrade 268  4% 
6 Fan System ‐ Equipment Upgrade 177 3% 
7  Paper: Premium Control Large Material  159  3% 
8 Material Handling ‐ Variable Speed Drive 155 3% 
9  Retrocommissioning 155  3% 
10 Kraft: Efficient Agitator 146 2% 
11  Fan System ‐ Variable Speed Drive 138  2% 
12 Compressed Air ‐ Outside Air Intake 130 2% 
13  Exterior Lighting ‐ Enhanced Controls 128  2% 
14 Paper: Efficient Pulp Screen  128 2% 
15  Area Lighting 113  2% 
16 Interior Lighting ‐ Networked Fixture Controls 112 2% 
17  Linear Lighting 104  2% 
18 Compressed Air ‐ End Use Optimization 104 2% 
19  Motors ‐ Synchronous Belts 98  2% 
20 Thermostat ‐ Wi‐Fi/Interactive 95 2% 
 Total of Top 20 Measures  4,547  74% 
  Total Cumulative Savings 6,149 100% 
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho

0
10
20
30
40
50
60
2021 2024 2027 2030 2033 2036 2039
GWh
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 845 of 1057

| 83 Applied Energy Group • www.appliedenergygroup.com

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. This year, Avista asked that AEG include the demand response potential
for their residential sector. In addition, since Avista is a dual-peaking utility, AEG was also asked to provide
summer demand response potential.
The updated analysis provides demand response potential and cost estimates for the 20-year planning
horizon of 2021-2040 to inform the development of Avista’s 2019 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 20-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 2021-2040 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 and 2016 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 846 of 1057
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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 2511 
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 2017 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 2018 to 2040.
Avista provided the number of customers by rate schedule for Washington and Idaho over the 2017-2023
timeframe. We used this data to calculate the average annual growth rate. We then applied these same
average annual growth rates to develop customer projections over the rest of the study timeframe, 2024-
2040. 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 2017 2018 2019 2020 2027 2037 
Washington 
Residential Service 222,837 225,529 227,521 229,618 243,398 245,335 
General Service 22,415  22,716  22,945  23,202  25,002  27,783 
Large General Service 1,835 1,845 1,844 1,844 1,844 1,844 
Extra Large General Service  20  20  20  20  20  20 

11 Excluding the two largest Schedule 25 and Schedule 25P customers.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 847 of 1057
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Customer Class 2017 2018 2019 2020 2027 2037 
Idaho            
Residential Service 112,001 113,733 115,077 116,390 126,029 127,452 
General Service 15,979  16,176  16,366  16,559  17,980  18,193 
Large General Service 1,114 1,115 1,115 1,115 1,115 1,115 
Extra Large General Service  11  11  11  11  11  11 

Forecasts of Winter and Summer Peak Demand
System Peak Demand
Avista provided the 2017 system winter and summer peak values as well as annual energy forecasts
through 2024. AEG used the annual energy growth rate by state and sector to forecast annual peak
demands through 2040, 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 by 4.1% by 2037, an average annual
increase of 0.21%.
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) 12
Peak Demand 2017 2018 2019 2020 2030 2037 
Winter System Peak  1496  1468  1434  1440  1509  1559 
Summer System Peak 1417 1389 1355 1362 1428 1477 

Coincident Peak Demand by Segment
To develop the coincident peak forecast for each segment, we started with electricity sales by customer
class. Avista provided electricity sales by rate schedule for the years 2017 through 2024. For the remaining
years of the forecast, 2025 through 2040, we projected electricity sales using the average annual growth
rate over the 2017 through 2021 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 2017 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.

12 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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load 
Factor 2017 2018 2019 2020 2027 2037 
Washington 
Residential 0.63 575 551 527 529 548 550 
General Service 0.60 82  80  81  82  88  89 
Large General Service 0.60 187 187 188 188 188 188 
Extra Large General Service 0.69 83  87  86  86  85  85 
Total  928 905 882 885 910 913 
Idaho 
Residential 0.65 264 256 248 251 267 270 
General Service 0.66 63  62  63  63  68  69 
Large General Service 0.66 99 99 98 98 98 98 
Extra Large General Service 0.60 52  56  56  55  54  54 
Total  477 473 464 467 487 490 

Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load 
Factor 2017 2018 2019 2020 2027 2037 
Washington 
Residential 0.50 568 544 520 523 525 528 
General Service 0.51 76  74  74  75  81  82 
Large General Service 0.51 173 173 173 173 174 174 
Extra Large General Service 0.57 68  71  71  71  70  70 
Total  885 862 839 842 845 849 
Idaho 
Residential 0.53 254 246 239 241 243 246 
General Service 0.57 57  57  57  57  58  59 
Large General Service 0.57 89 90 89 89 88 89 
Extra Large General Service 0.53 46  50  49  49  49  49 
Total  446 442 434 436 439 442 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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
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 the base year of analysis, 2017, system peak load for
the summer is 1,374 MW at the grid or generator level. Washington contributes 66% of summer system
peak while Idaho contributes 34%. Over the study period, summer coincident peak load is expected to
grow by an average of 0.48% annually from 2021-2040.
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 PacifiCorp. In the base year of analysis, 2016, system
peak load for the winter (a typical December weekday at 6:00 pm) is 8,170 MW at the grid or generator
level. The winter system peak is about 18% lower than the summer peak. Utah contributes 38% of winter
system peak, followed by Oregon at 32%, Wyoming at 15%, Washington 10%, and Idaho 3%, with California
at 2%. Over the study period, winter coincident peak load is expected to grow by an average of 0.59%
annually.
 ‐
 200
 400
 600
 800
 1,000
 1,200
 1,400
 1,600
MW
Washington Idaho
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 2014 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. AMI Saturations
are new to the analysis this year. We assume 100% AMI Saturation in the residential sector from the start
of the forecast horizon. Avista plans to have 100% AMI Saturation in the commercial sector by 2022 in
Washington and by 2024 in Idaho. They plan to roll out each over the course of two years starting in 2020
in Washington and 2022 in Idaho.
 ‐
 200
 400
 600
 800
 1,000
 1,200
 1,400
 1,600
 1,800
MW
Washington Idaho
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-6 2017 End Use Saturations by Customer Class, Washington
End Use Saturation by Equipment Type Residential C&I 
Space Heating Saturation  
Electric Furnace 7.4% 1.2% 
Air‐Source Heat Pump 19.4% 14.2% 
Total (Applicable for DR Analysis) 26.8% 15.5% 
Water Heating Saturation  
All equipment 42.2% 45.2% 
Electric Vehicle Saturation     
All equipment 0.2% ‐ 
Central AC Saturation    
All Equipment  38.4% 38.4% 
AMI Saturation    
All Equipment 100.0% 0.0% 
Appliance Saturation    
All Equipment 100.0% ‐ 

Table 6-7 2017 End Use Saturation by Customer Class, Idaho
End Use Saturation by Equipment Type Residential C&I 
Space Heating Saturation  
Electric Furnace 7.4% 1.2% 
Air‐Source Heat Pump 9.9% 14.2% 
Total (Applicable for DR Analysis) 17.3% 15.5% 
Water Heating Saturation  
All equipment 43.0% 45.2% 
Electric Vehicle Saturation     
All equipment 0.2% ‐ 
Central AC Saturation    
All Equipment  36.0% 36.0% 
AMI Saturation    
All Equipment 100.0% 0.0% 
Appliance Saturation    
All Equipment 100.0% ‐ 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 852 of 1057
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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 20-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).
Direct Load Control of Domestic Hot Water Heaters
The DLC Domestic Hot Water Heater program targets Avista’s Residential and General Service customers
in Washington and 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).
Smart Thermostats DLC Heating/Cooling
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.
Smart Appliances DLC
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
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
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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.
Electric Vehicle DLC Smart Chargers
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. We
also assume the DR program would only be available for residential service customers. The EVSE pilot
called daily demand response events from 4-8 PM. The events yielded impacts of 0.41 kW per charger
however the notifications only reached 82.5% of participants. Therefore, we assume a smaller impact per
charger of 0.34 kW per charger for this study.
Time-of-Use Pricing
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
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.
Variable 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.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Real Time Pricing
The Real Time Pricing rate is a dynamic rate that fluctuates throughout the day based on energy market
prices. Since it is a dynamic rate that will involve shifting energy use depending on the different prices
throughout the day, we assume only Large and Extra Large General Service customers will be able to
utilize this rate.
Ancillary Services
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.
Thermal 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.
Battery Energy Storage
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.
Behavioral
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.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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). As shown below, this study update includes a multitude of options that were not
considered in the previous study. Space Heating was considered 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.
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 
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 
Real Time Pricing Large General Service, 
Extra Large General Service 
Dynamic rate that fluctuates throughout the day 
based on energy market prices. Requires AMI 
technology.  
72 
Ancillary Services All Sectors 
Automated control of various building 
management systems or end‐uses through one of 
the mechanisms already described 
160 
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 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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DSM Option Eligible Sectors Mechanism 
Annual 
Event 
Hours 
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 
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.
Participation Rate Assumptions
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.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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   
7% 7% ‐ ‐ 
50/50 split 
between DLC 
Central AC and 
Smart Thermostats 
DLC of domestic 
hot water heaters 
(DHW) 
15% 5% ‐ ‐ 
Industry 
Experience‐ Brattle 
Study 
Smart Thermostats 
DLC Heating 12.5% 10% ‐ ‐ 
Agreed Upon 
Estimate with 
Avista 
Smart Thermostats 
DLC Cooling 7% 7% ‐ ‐ 
Agreed Upon 
Estimate with 
Avista (See DLC 
Central AC) 
Smart Appliances 
DLC 5% 5% ‐ ‐ 
2017 ISACA IT Risk 
Reward Barometer 
– US Consumer 
Results, October 
2017 
Third Party 
Contracts ‐ 15% 22.1% 20.9% Industry Experience 
Electric Vehicle DLC 
Smart Chargers 25%  ‐  ‐  ‐  Industry Experience 
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 2017 Smart 
Hours Study 
Real Time Pricing ‐ ‐ 3% 3%  Industry Experience 
Ancillary Services 15% 7.5% 7.5% 7.5% 
Industry 
Experience; C&I ½ 
of Residential 
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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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  1.22 kW  ‐  ‐ Average CAC Impacts across WA and ID in Avista 
territory 
DLC of 
domestic hot 
water heaters 
(DHW) 
0.58 kW 1.46 kW ‐ ‐ 
7th Plan, pg. 25 from Cadmus Report, Commercial: 
Res value multiplied by the CAC DLC ratio (small 
C&I impact /Res impact) 
Smart 
Thermostats 
DLC Heating 
1.5 kW  4 kW  ‐  ‐ 
Developed using the average of the 7th plan and 
the PSE 2010 DLC Pilot (WA), multiplied by ratio 
of HDD for the area 
Smart 
Thermostats 
DLC Cooling 
0.5 kW 1.22 kW ‐ ‐ Average CAC Impacts across WA and ID in Avista 
territory 
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 
0.34 kW  ‐  ‐  ‐ 
Avista EVSE DR Pilot Program for Residential‐ 
impact was 0.41 kW. 82.5% of customers received 
the DR notification so reducing to 0.34 kW. 
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 2017 Smart Hours Study; Summer Impacts 
Shown (Winter impacts ¾ summer) 
Real Time 
Pricing ‐  ‐  4%  4% Industry Experience; Same as VPP Large and Extra 
Large General Service 
Ancillary 
Services 4.8% 4.8% 4.8% 4.8% Industry Experience 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 
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 
DLC Electric Vehicle Charging $11.00    $1,200.00  $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 
Real Time Pricing $0.00    $0.00  $0.00 
Ancillary Services $0.00  $300.00 $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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 
DLC Central AC $67.50  $29.00  $23,863.32 
DLC Water Heating $0.00 $24.00 $24,128.89 
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 
DLC Electric Vehicle Charging $50.00  $24.00  $49,135.60 
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 
Real Time Pricing $300.00  $0.00  $24,194.41 
Ancillary Services $0.00 $0.00 $11,700.67 
Thermal Energy Storage $100.00  $0.00  $14,994.78 
Battery Energy Storage $25.00 $0.00 $8,017.36 
Behavioral $0.00 $0.00  $66,055.68 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 
DLC Electric Vehicle Charging $11.00    $1,200.00  $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 
Real Time Pricing $0.00    $0.00  $0.00 
Ancillary Services $0.00  $300.00 $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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-14 Marketing, Recruitment, Incentive, and Development Costs (Idaho)
DSM Option 
Annual 
Marketing/Recruitment 
Cost Per Participant 
Annual 
Incentive Per 
Participant 
Program 
Development 
Cost 
DLC Central AC $67.50 $29.00  $13,636.68 
DLC Water Heating $0.00 $24.00 $13,371.11 
DLC Smart Thermostats ‐ 
Heating $67.50 $20.00  $13,536.85 
DLC Smart Thermostats ‐ 
Cooling $67.50 $20.00 $13,636.68 
DLC Smart Appliances $50.00  $0.00  $13,415.30 
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 
Real Time Pricing $300.00  $0.00  $13,305.59 
Ancillary Services $0.00 $0.00 $7,049.33 
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 6.5% 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.
 Snapback. In this context, snapback refers to the amount of energy savings that result from DR
programs. We have assumed in this analysis that the amount of kWh savings from DR programs is
negligible since most of the reduction during events is typically shifted to other times of day, either
before or after the event.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 2040 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:
 In the TOU opt-in scenario, participants are split more evenly across the available pricing options,
leading to larger participation in the variable peak pricing rate and consequently a large VPP savings
potential.
 The highest potential option is Third Party Contracts which is expected to reach a savings potential of
23.2 MW by 2040.
 Since most of the participants are likely to be on the VPP pricing rate in the TOU Opt-in scenario, the
TOU potential is significantly lower than in the Opt-out case.
 After Third Party Contracts, the next three biggest potential options in winter include VPP, DLC Smart
Thermostats- Heating, and DLC Water Heating all of which are projected to contribute over 19 MW by
2040.
 The total potential savings in the winter TOU Opt-in scenario are expected to increase from 13 MW in
2021 to nearly 107 MW by 2040. The respective increase in the percentage of system peak goes from
0.9% in 2021 to 6.7% by 2040.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Figure 6-3 Summary of Potential Analysis for Avista (TOU Opt-In Winter Peak MW @Generator)

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 13.0 33.2 91.9 97.0 106.9 
Market Potential (% of baseline) 0.9% 2.3% 6.2% 6.4% 6.7% 
Potential Forecast 1,440 1,427 1,389 1,418 1,482 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.5  4.7  16.2  17.1 19.3 
DLC Smart Thermostats ‐ Heating 1.5 4.6 16.0 17.2 19.7 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.3 0.9 3.0 3.1 3.4 
Third Party Contracts 3.4  9.5  23.0  23.0 23.2 
DLC Electric Vehicle Charging 0.0 0.0 0.3 0.6 1.1 
Time‐of‐Use Opt‐in 0.7  2.2  6.7  6.9 7.2 
Time‐of‐Use Opt‐out 0.0 0.0 0.0 0.0 0.0 
Variable Peak Pricing Rates 2.3  7.0  20.0  20.5 21.5 
Real Time Pricing 0.1 0.3 0.6 0.6 0.6 
Ancillary Services 2.2  2.2  2.2  2.3 2.5 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.1  0.3  1.0  2.8 5.2 
Behavioral 0.8 1.6 2.9 3.0 3.2 
Achievable Potential (% of Baseline)      
DLC Central AC 0.00% 0.00% 0.00% 0.00% 0.00% 
DLC Water Heating 0.11%  0.32%  1.09%  1.13%  1.21% 
DLC Smart Thermostats ‐ Heating 0.10% 0.32% 1.08% 1.13% 1.24% 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.02% 0.06% 0.20% 0.21% 0.22% 
Third Party Contracts 0.23%  0.65%  1.55%  1.52%  1.46% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.07% 
Time‐of‐Use Opt‐in 0.05%  0.15%  0.46%  0.45%  0.45% 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 0.16%  0.48%  1.35%  1.35%  1.35% 
Real Time Pricing 0.01% 0.02% 0.04% 0.04% 0.04% 
Ancillary Services 0.15%  0.15%  0.15%  0.15%  0.16% 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.01%  0.02%  0.07%  0.18%  0.33% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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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 68.78 MW (4.3% of
winter system peak demand) by 2040 while Idaho is projected to save 38.16 MW (2.4% of winter system
peak demand) by 2040.
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 9.09 23.06 59.79 62.92 68.78 
Market Potential (% of System Peak) 0.6% 1.6% 4.0% 4.2% 4.3% 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating  0.99  3.00  10.38  11.07  12.60 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.19  0.57  1.96  2.04 2.21 
Third Party Contracts 2.76 7.28 14.58 14.64 14.78 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37 0.74 
Time‐of‐Use Opt‐in 0.49 1.49 4.50 4.57 4.72 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 1.62 4.85 13.25 13.49 14.00 
Real Time Pricing 0.07  0.17  0.38  0.38 0.38 
Ancillary Services 1.35 1.36 1.39 1.44 1.55 
Thermal Energy Storage  ‐  ‐  ‐  ‐  ‐ 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.55  1.07  1.96  2.00 2.08 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (Winter MW) 3.87 10.15 32.07 34.11 38.16 
Market Potential (% of System Peak) 0.3% 0.7% 2.2% 2.3% 2.4% 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 0.53 1.61 5.60 6.00 6.88 
DLC Smart Thermostats ‐ Heating  0.53  1.61  5.64  6.10 7.14 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.10  0.30  1.04  1.10 1.24 
Third Party Contracts 0.64 2.25 8.37 8.40 8.47 
DLC Electric Vehicle Charging 0.00  0.02  0.09  0.19 0.39 
Time‐of‐Use Opt‐in 0.22 0.67 2.24 2.32 2.47 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 0.70 2.16 6.73 6.97 7.48 
Real Time Pricing 0.04  0.11  0.21  0.21 0.21 
Ancillary Services 0.82 0.82 0.84 0.87 0.93 
Thermal Energy Storage  ‐  ‐  ‐  ‐  ‐ 
Battery Energy Storage 0.03 0.08 0.35 0.98 1.87 
Behavioral 0.26  0.51  0.95  0.99 1.07 
Cost Results
Table 6-18 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Third Party Contracts option delivers the highest savings at approximately $74.8/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 lowest levelized cost among all the DR options. It delivers 21.8
MW of savings in 2040 at $21.01/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of CPP deployment costs.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter)
DR Option 
Washington 
2021‐2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Winter 
Potential MW in 2040 
DLC Central AC ‐ ‐ ‐ ‐ 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating  $46.17 $45.21 $45.83 19.74 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ 
DLC Smart Appliances $237.04  $240.63 $238.30 3.45 
Third Party Contracts $74.80 $74.80 $74.80 23.25 
DLC Electric Vehicle Charging  $688.90  $698.35 $692.17 1.14 
Time‐of‐Use Opt‐in $45.56 $54.73 $48.68 7.20 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates $21.60 $22.81 $22.01 21.48 
Real Time Pricing $194.77  $191.22 $193.51 0.58 
Ancillary Services $90.19 $94.80 $91.74 2.48 
Thermal Energy Storage ‐ ‐ ‐ ‐ 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $128.58  $134.97 $130.75 3.15 

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:
 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 27.4 MW by 2040.
 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 (6.6 MW by 2040).
 After TOU, the next three biggest potential options in winter include Third Party Contracts, DLC Smart
Thermostats- Heating, and DLC Water Heating all of which are projected to contribute over 19 MW by
2040.
 The total potential savings in the winter TOU Opt-out scenario are expected to increase from 45.6 MW
in 2021 to nearly 112 MW by 2040. The respective increase in the percentage of system peak goes
from 3.1% in 2021 to 7.0% by 2040. In this scenario, the potential savings starts at a much faster rate
than in the opt-in case as the participation in TOU will represent a much bigger portion initially.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,453  1,460  1,481  1,515  1,589 
Market Potential (Winter MW) 45.6 56.7 96.8 101.9 111.9 
Market Potential (% of baseline) 3.1% 3.9% 6.5% 6.7% 7.0% 
Potential Forecast 1,407 1,403 1,384 1,413 1,477 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.5  4.7  16.2  17.1 19.3 
DLC Smart Thermostats ‐ Heating 1.5 4.6 16.0 17.2 19.7 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.3 0.9 3.0 3.1 3.4 
Third Party Contracts 3.4  9.5  23.0  23.0 23.2 
DLC Electric Vehicle Charging 0.0 0.0 0.3 0.6 1.1 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 35.7 31.7 25.9 26.4 27.4 
Variable Peak Pricing Rates 0.1  1.2  6.1  6.3 6.6 
Real Time Pricing 0.0 0.1 0.2 0.2 0.2 
Ancillary Services 2.2  2.2  2.2  2.3 2.5 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.1  0.3  1.0  2.8 5.2 
Behavioral 0.8 1.6 2.9 3.0 3.2 
Achievable Potential (% of Baseline)       
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 0.11%  0.32%  1.09%  1.13%  1.21% 
DLC Smart Thermostats ‐ Heating 0.10% 0.32% 1.08% 1.13% 1.24% 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.02% 0.06% 0.20% 0.21% 0.22% 
Third Party Contracts 0.23%  0.65%  1.55%  1.52%  1.46% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.07% 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 2.46% 2.17% 1.75% 1.74% 1.73% 
Variable Peak Pricing Rates 0.01%  0.08%  0.41%  0.41%  0.41% 
Real Time Pricing 0.00% 0.01% 0.01% 0.01% 0.01% 
Ancillary Services 0.15%  0.15%  0.15%  0.15%  0.16% 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.01%  0.02%  0.07%  0.18%  0.33% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 871 of 1057
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  | 109 Applied Energy Group • www.appliedenergygroup.com
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)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (Winter MW) 8.39 21.45 55.77 58.77 64.34 
Market Potential (% of System Peak) 0.6% 1.6% 4.0% 4.1% 4.3% 
Achievable Potential (MW)      
DLC Central AC 0.39  1.19  4.04  4.32 4.92 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.39 1.20 4.15 4.44 5.06 
DLC Smart Appliances 0.19  0.57  1.96  2.04 2.21 
Third Party Contracts 2.44 6.50 13.04 13.10 13.23 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37 0.74 
Time‐of‐Use Opt‐in 0.48 1.44 4.36 4.43 4.58 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 1.58 4.70 12.85 13.09 13.59 
Real Time Pricing 0.06  0.16  0.34  0.34 0.33 
Ancillary Services 1.21 1.22 1.25 1.30 1.40 
Thermal Energy Storage 0.03  0.14  0.45  0.46 0.48 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.54  1.06  1.93  1.97 2.05 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 872 of 1057
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  | 110 Applied Energy Group • www.appliedenergygroup.com
Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (Winter MW) 3.56 9.40 30.20 31.80 35.64 
Market Potential (% of System Peak) 0.3% 0.7% 2.2% 2.2% 2.4% 
Achievable Potential (MW)      
DLC Central AC 0.22  0.65  2.28  2.43  2.85 
DLC Water Heating 0.53 1.61 5.68 6.00 6.88 
DLC Smart Thermostats ‐ Heating ‐  ‐  ‐  ‐  ‐ 
DLC Smart Thermostats ‐ Cooling 0.22 0.66 2.34 2.50 2.94 
DLC Smart Appliances 0.10  0.30  1.06  1.10  1.24 
Third Party Contracts 0.57 2.01 7.55 7.57 7.64 
DLC Electric Vehicle Charging 0.00  0.02  0.11  0.19  0.39 
Time‐of‐Use Opt‐in 0.21 0.64 2.14 2.20 2.35 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 0.67 2.06 6.42 6.61 7.10 
Real Time Pricing 0.04  0.10  0.19  0.19  0.19 
Ancillary Services 0.74 0.74 0.77 0.79 0.85 
Thermal Energy Storage 0.00  0.03  0.29  0.30  0.32 
Battery Energy Storage 0.03 0.08 0.45 0.98 1.87 
Behavioral 0.25  0.49  0.92  0.95  1.03 
Cost Results
Table 6-22 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The TOU Opt-out option delivers the highest savings at approximately $62.87/kW-year cost and has
the potential to contribute 27.42 MW of savings in 2040.
 The Third Party Contracts option delivers the second highest savings at approximately $74.8/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 lowest levelized cost among all the DR options. It delivers 21.8
MW of savings in 2040 at $35.76/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of CPP deployment costs.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 873 of 1057
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  | 111 Applied Energy Group • www.appliedenergygroup.com
Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter
DR Option 
Washington 
2021‐2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Winter 
Potential MW in 2040 
DLC Central AC ‐ ‐ ‐ ‐ 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating  $46.17 $45.21 $45.83 19.74 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ 
DLC Smart Appliances $237.04  $240.63 $238.30 3.45 
Third Party Contracts $74.80 $74.80 $74.80 23.25 
DLC Electric Vehicle Charging  $688.90  $698.35 $692.17 1.14 
Time‐of‐Use Opt‐in ‐ ‐ ‐ ‐ 
Time‐of‐Use Opt‐out $58.06 $72.18 $62.87 27.42 
Variable Peak Pricing Rates $35.30 $36.64 $35.76 6.59 
Real Time Pricing $659.87  $578.41 $193.51 0.18 
Ancillary Services $90.19 $94.80 $91.74 2.48 
Thermal Energy Storage ‐ ‐ ‐ ‐ 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $128.58  $134.97 $130.75 3.15 

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:
 Similar to the winter case, in the TOU opt-in scenario, many customers will choose to go on the
variable peak pricing rate leading to a large VPP savings potential.
 The highest potential option is Third Party Contracts which is expected to reach a savings potential of
20.87 MW by 2040.
 Since most of the participants are likely to be on the VPP pricing rate in the TOU Opt-in scenario, the
TOU potential is significantly lower than in the Opt-out case.
 After Third Party Contracts, the next two biggest potential options in summer include VPP, and DLC
Water Heating each of which are projected to contribute over 19 MW by 2040. Space cooling options
are split across DLC Smart Thermostat and DLC Central AC options. Together they contribute 15.78
MW by 2040.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 874 of 1057
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  | 112 Applied Energy Group • www.appliedenergygroup.com
 The total potential savings in the summer TOU Opt-in scenario are expected to increase from 11.9 MW
in 2021 to 100 MW by 2040. The respective increase in the percentage of system peak goes from 0.9%
in 2021 to 6.6% by 2040 (very similar to the winter percentages).

Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator)

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 875 of 1057
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  | 113 Applied Energy Group • www.appliedenergygroup.com
Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 11.9 30.8 85.6 90.6 100.0 
Market Potential (% of baseline) 0.9% 2.2% 6.1% 6.3% 6.6% 
Potential Forecast 1,362 1,350 1,315 1,343 1,405 
Achievable Potential (MW)           
DLC Central AC 0.61 1.84 6.32 6.75 7.78 
DLC Water Heating 1.54  4.68  16.23  17.13  19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.61  1.85  6.49  6.93  8.00 
DLC Smart Appliances 0.29 0.88 3.01 3.14 3.45 
Third Party Contracts 3.01  8.52  20.60  20.67  20.87 
DLC Electric Vehicle Charging 0.01 0.05 0.30 0.55 1.14 
Time‐of‐Use Opt‐in 0.68  2.09  6.50  6.63  6.93 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 2.25  6.76  19.27  19.70  20.69 
Real Time Pricing 0.10 0.25 0.52 0.52 0.52 
Ancillary Services 1.95  1.96  2.02  2.09  2.25 
Thermal Energy Storage 0.03 0.17 0.74 0.76 0.80 
Battery Energy Storage 0.08  0.26  1.10  2.77  5.21 
Behavioral 0.79 1.55 2.85 2.92 3.08 
Achievable Potential (% of Baseline)           
DLC Central AC 0.04% 0.13% 0.45% 0.47% 0.52% 
DLC Water Heating 0.11%  0.34%  1.16%  1.19%  1.28% 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.04%  0.13%  0.46%  0.48%  0.53% 
DLC Smart Appliances 0.02% 0.06% 0.22% 0.22% 0.23% 
Third Party Contracts 0.22%  0.62%  1.47%  1.44%  1.39% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.08% 
Time‐of‐Use Opt‐in 0.05%  0.15%  0.46%  0.46%  0.46% 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 0.16%  0.49%  1.38%  1.37%  1.37% 
Real Time Pricing 0.01% 0.02% 0.04% 0.04% 0.03% 
Ancillary Services 0.14%  0.14%  0.14%  0.15%  0.15% 
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.05% 
Battery Energy Storage 0.01%  0.02%  0.08%  0.19%  0.35% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 876 of 1057
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  | 114 Applied Energy Group • www.appliedenergygroup.com
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 WashingtonTOU Opt-In (Summer MW
@Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 8.39 21.45 55.77 58.77 64.34 
Market Potential (% of System Peak) 0.6% 1.6% 4.0% 4.1% 4.3% 
Achievable Potential (MW)      
DLC Central AC 0.39  1.19  4.04  4.32  4.92 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.39 1.20 4.15 4.44 5.06 
DLC Smart Appliances 0.19  0.57  1.96  2.04  2.21 
Third Party Contracts 2.44 6.50 13.04 13.10 13.23 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37  0.74 
Time‐of‐Use Opt‐in 0.48 1.44 4.36 4.43 4.58 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates 1.58 4.70 12.85 13.09 13.59 
Real Time Pricing 0.06  0.16  0.34  0.34  0.33 
Ancillary Services 1.21 1.22 1.25 1.30 1.40 
Thermal Energy Storage 0.03  0.14  0.45  0.46  0.48 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.54  1.06  1.93  1.97  2.05 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 877 of 1057
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  | 115 Applied Energy Group • www.appliedenergygroup.com
Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,453  1,460  1,481  1,515  1,589 
Market Potential (MW) 3.56 9.40 30.20 31.80 35.64 
Market Potential (% of System Peak) 0.3% 0.7% 2.2% 2.2% 2.4% 
Achievable Potential (MW)      
DLC Central AC 0.22  0.65  2.28  2.43  2.85 
DLC Water Heating 0.53 1.61 5.68 6.00 6.88 
DLC Smart Thermostats ‐ Heating  0.00  0.00  0.00  0.00  0.00 
DLC Smart Thermostats ‐ Cooling 0.22 0.66 2.34 2.50 2.94 
DLC Smart Appliances 0.10  0.30  1.06  1.10  1.24 
Third Party Contracts 0.57 2.01 7.55 7.57 7.64 
DLC Electric Vehicle Charging 0.00  0.02  0.11  0.19  0.39 
Time‐of‐Use Opt‐in 0.21 0.64 2.14 2.20 2.35 
Time‐of‐Use Opt‐out          
Variable Peak Pricing Rates 0.67 2.06 6.42 6.61 7.10 
Real Time Pricing 0.04  0.10  0.19  0.19  0.19 
Ancillary Services 0.74 0.74 0.77 0.79 0.85 
Thermal Energy Storage 0.00  0.03  0.29  0.30  0.32 
Battery Energy Storage 0.03 0.08 0.45 0.98 1.87 
Behavioral 0.25  0.49  0.92  0.95  1.03 
Cost Results
Table 6-26 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Third Party Contracts option delivers the highest savings at approximately $83.39/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
21.36 MW of savings in 2040 at $22.85/kW-year system wide. Enabling technology purchase and
installation costs for enhancing customer response is a large part of CPP deployment costs.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 878 of 1057
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  | 116 Applied Energy Group • www.appliedenergygroup.com
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In
DR Option 
Washington 2021‐
2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Summer 
Potential MW in 
2040 
DLC Central AC $120.70 $118.55 $119.95 7.78 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling $131.00 $127.06 $129.62 8.00 
DLC Smart Appliances $237.04 $240.63 $238.30 3.45 
Third Party Contracts $83.62 $82.98 $83.39 20.69 
DLC Electric Vehicle Charging $688.90 $698.35 $692.16 1.14 
Time‐of‐Use Opt‐in $46.99 $57.66 $50.55 6.93 
Time‐of‐Use Opt‐out ‐ ‐ ‐ ‐ 
Variable Peak Pricing Rates $22.26 $24.05 $22.85 20.36 
Real Time Pricing $218.89 $212.35 $193.51 0.33 
Ancillary Services $99.98 $104.78 $101.56 2.25 
Thermal Energy Storage $610.99 $591.88 $603.36 0.80 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $130.16 $140.39 $133.57 2.05 

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:
 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 26.2 MW by 2040.
 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 (6.35 MW by 2040).
 After TOU Opt-out, the next two biggest potential options in summer include Third Party Contracts,
and DLC Water Heating each of which are projected to contribute over 19 MW by 2040. Space cooling
options are split across DLC Smart Thermostat and DLC Central AC options. Together they contribute
15.78 MW by 2040.
 The total potential savings in the summer TOU Opt-in scenario are expected to increase from 43.2
MW in 2021 to 104.5 MW by 2040. The respective increase in the percentage of system peak goes
from 3.1% in 2021 to 6.9% by 2040 (very similar to the winter percentages for the TOU Opt-in case).
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 879 of 1057
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  | 117 Applied Energy Group • www.appliedenergygroup.com

Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator)

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 880 of 1057
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  | 118 Applied Energy Group • www.appliedenergygroup.com
Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 43.2 53.3 90.1 95.1 104.5 
Market Potential (% of baseline) 3.1% 3.9% 6.4% 6.6% 6.9% 
Potential Forecast 1,330 1,327 1,310 1,339 1,400 
Achievable Potential (MW)           
DLC Central AC 0.61 1.84 6.29 6.75 7.78 
DLC Water Heating 1.54  4.68  16.15  17.13  19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.61  1.85  6.45  6.93  8.00 
DLC Smart Appliances 0.29 0.88 3.00 3.14 3.45 
Third Party Contracts 3.01  8.52  20.59  20.67  20.87 
DLC Electric Vehicle Charging 0.01 0.05 0.28 0.55 1.14 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 34.18 30.26 24.70 25.18 26.20 
Variable Peak Pricing Rates 0.08  1.17  5.90  6.05  6.35 
Real Time Pricing 0.04 0.08 0.16 0.16 0.16 
Ancillary Services 1.95  1.96  2.02  2.09  2.25 
Thermal Energy Storage 0.03 0.17 0.74 0.76 0.80 
Battery Energy Storage 0.08  0.26  1.00  2.77  5.21 
Behavioral 0.79 1.55 2.84 2.92 3.08 
Achievable Potential (% of Baseline)           
DLC Central AC 0.04% 0.13% 0.45% 0.47% 0.52% 
DLC Water Heating 0.11%  0.34%  1.15%  1.19%  1.28% 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.04%  0.13%  0.46%  0.48%  0.53% 
DLC Smart Appliances 0.02% 0.06% 0.21% 0.22% 0.23% 
Third Party Contracts 0.22%  0.62%  1.47%  1.44%  1.39% 
DLC Electric Vehicle Charging 0.00% 0.00% 0.02% 0.04% 0.08% 
Time‐of‐Use Opt‐in ‐  ‐  ‐  ‐  ‐ 
Time‐of‐Use Opt‐out 2.49% 2.19% 1.76% 1.76% 1.74% 
Variable Peak Pricing Rates 0.01%  0.08%  0.42%  0.42%  0.42% 
Real Time Pricing 0.00% 0.01% 0.01% 0.01% 0.01% 
Ancillary Services 0.14%  0.14%  0.14%  0.15%  0.15% 
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.05% 
Battery Energy Storage 0.01%  0.02%  0.07%  0.18%  0.33% 
Behavioral 0.06% 0.11% 0.20% 0.20% 0.20% 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 881 of 1057
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  | 119 Applied Energy Group • www.appliedenergygroup.com
Table 6-28 and Table 6-29 show demand savings by individual DR option for the states of Washington
and Idaho separately.
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW
@Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 30.37 37.02 58.77 61.78 67.36 
Market Potential (% of System Peak) 2.2% 2.7% 4.2% 4.3% 4.5% 
Achievable Potential (MW)      
DLC Central AC 0.39  1.19  4.04  4.32  4.92 
DLC Water Heating 1.01 3.06 10.55 11.13 12.38 
DLC Smart Thermostats ‐ Heating  0.00  0.00  0.00  0.00  0.00 
DLC Smart Thermostats ‐ Cooling 0.39 1.20 4.15 4.44 5.06 
DLC Smart Appliances 0.19  0.57  1.96  2.04  2.21 
Third Party Contracts 2.44 6.50 13.04 13.10 13.23 
DLC Electric Vehicle Charging 0.01  0.03  0.19  0.37  0.74 
Time‐of‐Use Opt‐in      
Time‐of‐Use Opt‐out 24.02  21.09  16.50  16.75  17.26 
Variable Peak Pricing Rates 0.07 0.76 3.94 4.02 4.17 
Real Time Pricing 0.02  0.03  0.10  0.10  0.10 
Ancillary Services 1.21 1.22 1.25 1.30 1.40 
Thermal Energy Storage 0.03  0.14  0.45  0.46  0.48 
Battery Energy Storage 0.05 0.17 0.65 1.79 3.34 
Behavioral 0.54  1.06  1.93  1.97  2.05 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 882 of 1057
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  | 120 Applied Energy Group • www.appliedenergygroup.com
Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW) 1,374  1,380  1,400  1,434  1,505 
Market Potential (MW) 12.85 16.24 31.37 33.32 37.19 
Market Potential (% of System Peak) 0.9% 1.2% 2.2% 2.3% 2.5% 
Achievable Potential (MW)      
DLC Central AC 0.22  0.65  2.24  2.43  2.85 
DLC Water Heating 0.53 1.61 5.60 6.00 6.88 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.22 0.66 2.30 2.50 2.94 
DLC Smart Appliances 0.10  0.30  1.04  1.10  1.24 
Third Party Contracts 0.57 2.01 7.55 7.57 7.64 
DLC Electric Vehicle Charging 0.00  0.02  0.09  0.19  0.39 
Time‐of‐Use Opt‐in ‐ ‐ ‐ ‐ ‐ 
Time‐of‐Use Opt‐out 10.17  9.17  8.20  8.43  8.94 
Variable Peak Pricing Rates 0.01 0.41 1.96 2.03 2.18 
Real Time Pricing 0.02  0.05  0.06  0.06  0.06 
Ancillary Services 0.74 0.74 0.76 0.79 0.85 
Thermal Energy Storage 0.00  0.03  0.29  0.30  0.32 
Battery Energy Storage 0.03 0.08 0.35 0.98 1.87 
Behavioral 0.25  0.49  0.91  0.95  1.03 
Cost Results
Table 6-30 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Third Party Contracts option delivers the highest savings at approximately $83.39/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
6.25 MW of savings in 2040 at $37.14/kW-year system wide. Enabling technology purchase and
installation costs for enhancing customer response is a large part of CPP deployment costs.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 883 of 1057
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  | 121 Applied Energy Group • www.appliedenergygroup.com
Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out
DR Option 
Washington 2021‐
2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Summer 
Potential MW in 
2040 
DLC Central AC $120.70 $118.55 $119.95 7.78 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling $131.00 $127.06 $129.62 8.00 
DLC Smart Appliances $237.04 $240.63 $238.30 3.45 
Third Party Contracts $83.62 $82.98 $83.39 20.87 
DLC Electric Vehicle Charging $688.90 $698.35 $692.16 1.14 
Time‐of‐Use Opt‐in ‐ ‐ ‐ ‐ 
Time‐of‐Use Opt‐out $60.46 $76.46 $65.81 26.20 
Variable Peak Pricing Rates $36.38 $38.66 $37.14 6.25 
Real Time Pricing $741.22 $641.72 $193.51 0.10 
Ancillary Services $99.98 $104.78 $101.56 2.25 
Thermal Energy Storage $610.99 $591.88 $603.36 0.80 
Battery Energy Storage $389.31 $393.28 $390.70 5.21 
Behavioral $130.16 $140.39 $133.57 2.05 

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:
 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 largest savings potential in the stand-alone case and is expected to reach 32.9 MW by
2040.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 884 of 1057
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  | 122 Applied Energy Group • www.appliedenergygroup.com
 Since the different rate options are not allowed to influence other rates in the stand-alone scenario,
each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
 After TOU Opt-in, the next two biggest potential options in winter include VPP and Third Party
Contracts all of which are projected to contribute over 23 MW by 2040.
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator)

‐
20
40
60
80
100
120
140
160
2021 2022 2025 2030 2040
Achievable Potential 
(MW)
Time‐of‐Use Opt‐out
Time‐of‐Use Opt‐in
DLC Electric Vehicle Charging
Third Party Contracts
DLC Smart Thermostats ‐ Heating
DLC Smart Thermostats ‐ Cooling
Battery Energy Storage
Thermal Energy Storage
Behavioral
Real Time Pricing
Variable Peak Pricing Rates
DLC Smart Appliances
DLC Water Heating
DLC Central AC
Ancillary Services
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 885 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 123 Applied Energy Group • www.appliedenergygroup.com
Table 6-32 Achievable DR Potential by Option (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,453  1,460  1,481  1,515  1,589 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.5 4.7 16.2 17.1 19.3 
DLC Smart Thermostats ‐ Heating 1.5 4.6 16.0 17.2 19.7 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.3  0.9  3.0  3.1 3.4 
Third Party Contracts 3.4 9.5 23.0 23.0 23.2 
DLC Electric Vehicle Charging 0.0  0.0  0.3  0.6 1.1 
Time‐of‐Use Opt‐in 0.7 2.3 8.0 8.2 8.6 
Time‐of‐Use Opt‐out 36.5  33.6  30.9  31.6 32.9 
Variable Peak Pricing Rates 2.4 7.7 27.2 27.9 29.5 
Real Time Pricing 0.1  0.3  1.1  1.1 1.1 
Ancillary Services 2.2 2.2 2.2 2.3 2.5 
Thermal Energy Storage  ‐  ‐  ‐  ‐  ‐ 
Battery Energy Storage 0.1 0.3 1.0 2.8 5.2 
Behavioral 0.8  1.7  3.4  3.5 3.7 
Achievable Potential (% of Baseline)      
DLC Central AC ‐  ‐  ‐  ‐  ‐ 
DLC Water Heating 0.11% 0.32% 1.09% 1.13% 1.21% 
DLC Smart Thermostats ‐ Heating 0.10% 0.32% 1.08% 1.13% 1.24% 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.02%  0.06%  0.20%  0.21%  0.22% 
Third Party Contracts 0.23% 0.65% 1.55% 1.52% 1.46% 
DLC Electric Vehicle Charging 0.00%  0.00%  0.02%  0.04%  0.07% 
Time‐of‐Use Opt‐in 0.05% 0.16% 0.54% 0.54% 0.54% 
Time‐of‐Use Opt‐out 2.51%  2.30%  2.09%  2.08%  2.07% 
Variable Peak Pricing Rates 0.16% 0.53% 1.84% 1.84% 1.86% 
Real Time Pricing 0.01%  0.02%  0.08%  0.08%  0.07% 
Ancillary Services 0.15% 0.15% 0.15% 0.15% 0.16% 
Thermal Energy Storage 0.00%  0.00%  0.00%  0.00%  0.00% 
Battery Energy Storage 0.01% 0.02% 0.07% 0.18% 0.33% 
Behavioral 0.06%  0.11%  0.23%  0.23%  0.23% 

Table 6-33 and Table 6-34 show demand savings by individual DR option for the states of Washington
and Idaho separately. As mentioned above, the programs with the largest potential savings are TOU Opt-
out, VPP, and Third Party Contracts each individually contributing over 14.5 MW of savings in the
Washington Territory alone.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 886 of 1057
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  | 124 Applied Energy Group • www.appliedenergygroup.com
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 1.01  3.06  10.55  11.13  12.38 
DLC Smart Thermostats ‐ Heating 0.99 3.00 10.38 11.07 12.60 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.19 0.57 1.96 2.04 2.21 
Third Party Contracts 2.76  7.28  14.58  14.64  14.78 
DLC Electric Vehicle Charging 0.01 0.03 0.19 0.37 0.74 
Time‐of‐Use Opt‐in 0.50  1.58  5.32  5.42 5.63 
Time‐of‐Use Opt‐out 25.54 23.42 20.51 20.85 21.55 
Variable Peak Pricing Rates 1.67  5.34  18.02  18.41  19.20 
Real Time Pricing 0.07 0.22 0.73 0.73 0.73 
Ancillary Services 1.35  1.36  1.39  1.44 1.55 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.05  0.17  0.65  1.79 3.34 
Behavioral 0.56 1.12 2.28 2.33 2.44 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 887 of 1057
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  | 125 Applied Energy Group • www.appliedenergygroup.com
Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)      
DLC Central AC ‐ ‐ ‐ ‐ ‐ 
DLC Water Heating 0.53  1.61  5.60  6.00 6.88 
DLC Smart Thermostats ‐ Heating 0.53 1.61 5.64 6.10 7.14 
DLC Smart Thermostats ‐ Cooling ‐ ‐ ‐ ‐ ‐ 
DLC Smart Appliances 0.10 0.30 1.04 1.10 1.24 
Third Party Contracts 0.64  2.25  8.37  8.40 8.47 
DLC Electric Vehicle Charging 0.00 0.02 0.09 0.19 0.39 
Time‐of‐Use Opt‐in 0.22  0.71  2.66  2.75 2.95 
Time‐of‐Use Opt‐out 10.93 10.20 10.41 10.72 11.38 
Variable Peak Pricing Rates 0.72  2.35  9.19  9.54  10.29 
Real Time Pricing 0.04 0.12 0.41 0.40 0.40 
Ancillary Services 0.82  0.82  0.84  0.87 0.93 
Thermal Energy Storage ‐ ‐ ‐ ‐ ‐ 
Battery Energy Storage 0.03  0.08  0.35  0.98 1.87 
Behavioral 0.27 0.54 1.10 1.15 1.26 
Cost Results
Table 6-35 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 29.49
MW of savings in 2040 at $20.67/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of VPP deployment costs.
 The second lowest levelized cost among all the DR options is DLC Smart Thermostats-Heating. It
delivers 29.49 MW of savings in 2040 at $20.67/kW-year system wide. Enabling technology purchase
and installation costs for enhancing customer response is a large part of VPP deployment costs.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 888 of 1057
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  | 126 Applied Energy Group • www.appliedenergygroup.com
Table 6-35 DR Program Costs and Potential (Winter)
DR Option 
Washington 
2021‐2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Winter 
Potential MW in 2040 
DLC Central AC     
DLC Water Heating $139.94 $138.67 $139.40 19.27 
DLC Smart Thermostats ‐ Heating  $46.17 $45.21 $45.83 19.74 
DLC Smart Thermostats ‐ Cooling     
DLC Smart Appliances $237.04  $240.63 $238.56 3.45 
Third Party Contracts $74.80 $74.80 $74.80 23.25 
DLC Electric Vehicle Charging  $688.90  $698.35 $692.17 1.14 
Time‐of‐Use Opt‐in $43.07 $52.26 $46.40 8.58 
Time‐of‐Use Opt‐out $51.59 $65.02 $56.45 32.93 
Variable Peak Pricing Rates $20.23 $21.38 $20.67 29.49 
Real Time Pricing $104.67  $104.18 $104.49 1.13 
Ancillary Services $90.19 $94.80 $91.95 2.48 
Thermal Energy Storage     
Battery Energy Storage $389.24 $393.20 $390.86 5.22 
Behavioral $120.61  $126.65 $122.66 3.70 

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:
 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 largest savings potential in the stand-alone case and is expected to reach 31.4 MW by
2040.
 Since the different rate options are not allowed to influence other rates in the stand-alone scenario,
each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
 After TOU Opt-in, the next two biggest potential options in winter include VPP and Third Party
Contracts all of which are projected to contribute over 20 MW by 2040. DLC Water Heating also has
a high savings potential projected to reach 19.3 MW by 2040.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 889 of 1057
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  | 127 Applied Energy Group • www.appliedenergygroup.com
Figure 6-9 Summary of Summer Potential by Option (MW @Generator)

‐
20
40
60
80
100
120
140
160
2021 2022 2025 2030 2040
Achievable Potential 
(MW)
Time‐of‐Use Opt‐out
Time‐of‐Use Opt‐in
DLC Electric Vehicle Charging
Third Party Contracts
DLC Smart Thermostats ‐ Heating
DLC Smart Thermostats ‐ Cooling
Battery Energy Storage
Thermal Energy Storage
Behavioral
Real Time Pricing
Variable Peak Pricing Rates
DLC Smart Appliances
DLC Water Heating
DLC Central AC
Ancillary Services
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 890 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 128 Applied Energy Group • www.appliedenergygroup.com
Table 6-36 Achievable DR Potential by Option (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Total System Peak (MW)  1,374  1,380  1,400  1,434  1,505 
Achievable Potential (MW)      
DLC Central AC 0.6  1.9  6.5  6.9  8.0 
DLC Water Heating 1.5 4.7 16.2 17.1 19.3 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.6 1.9 6.5 6.9 8.0 
DLC Smart Appliances 0.3  0.9  3.0  3.1  3.4 
Third Party Contracts 3.0 8.5 20.6 20.7 20.9 
DLC Electric Vehicle Charging 0.0  0.0  0.3  0.6  1.1 
Time‐of‐Use Opt‐in 0.7 2.2 7.7 7.9 8.3 
Time‐of‐Use Opt‐out 34.9  32.1  29.4  30.1  31.4 
Variable Peak Pricing Rates 2.3 7.3 25.7 26.4 27.9 
Real Time Pricing 0.1  0.2  0.7  0.7  0.7 
Ancillary Services 1.9 2.0 2.0 2.1 2.2 
Thermal Energy Storage 0.6  1.1  2.2  2.3  2.4 
Battery Energy Storage 0.0 0.2 0.8 0.8 0.8 
Behavioral 0.1  0.3  1.0  2.8  5.2 
Achievable Potential (% of Baseline)      
DLC Central AC 0.04%  0.13%  0.46%  0.48%  0.53% 
DLC Water Heating 0.11% 0.34% 1.15% 1.19% 1.28% 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling 0.04% 0.13% 0.46% 0.48% 0.53% 
DLC Smart Appliances 0.02%  0.06%  0.21%  0.22%  0.23% 
Third Party Contracts 0.22% 0.62% 1.47% 1.44% 1.39% 
DLC Electric Vehicle Charging 0.00%  0.00%  0.02%  0.04%  0.08% 
Time‐of‐Use Opt‐in 0.05% 0.16% 0.55% 0.55% 0.55% 
Time‐of‐Use Opt‐out 2.54%  2.32%  2.10%  2.10%  2.09% 
Variable Peak Pricing Rates 0.16% 0.53% 1.83% 1.84% 1.85% 
Real Time Pricing 0.00%  0.01%  0.05%  0.05%  0.04% 
Ancillary Services 0.14% 0.14% 0.14% 0.15% 0.15% 
Thermal Energy Storage 0.04%  0.08%  0.16%  0.16%  0.16% 
Battery Energy Storage 0.00% 0.01% 0.06% 0.06% 0.06% 
Behavioral 0.01%  0.02%  0.07%  0.19%  0.35% 

Table 6-37 and Table 6-38 show summer demand savings by individual DR option for the states of
Washington and Idaho separately. As mentioned above, the programs with the largest potential savings
are TOU Opt-out, VPP, and Third Party Contracts each individually contributing over 13 MW of savings in
the Washington Territory alone.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 891 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 129 Applied Energy Group • www.appliedenergygroup.com
Table 6-37 Achievable DR Potential by Option for Washington (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)           
DLC Central AC 0.39 1.20 4.15 4.44 5.06 
DLC Water Heating 1.01  3.06  10.55  11.13  12.38 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.39  1.20  4.15  4.44  5.06 
DLC Smart Appliances 0.19 0.57 1.96 2.04 2.21 
Third Party Contracts 2.44  6.50  13.04  13.10  13.23 
DLC Electric Vehicle Charging 0.01 0.03 0.19 0.37 0.74 
Time‐of‐Use Opt‐in 0.48  1.53  5.15  5.25  5.45 
Time‐of‐Use Opt‐out 24.52 22.43 19.65 19.98 20.68 
Variable Peak Pricing Rates 1.63  5.17  17.46  17.84  18.62 
Real Time Pricing 0.07 0.20 0.65 0.65 0.65 
Ancillary Services 1.21  1.22  1.25  1.30  1.40 
Thermal Energy Storage 0.03 0.14 0.47 0.48 0.50 
Battery Energy Storage 0.05  0.17  0.65  1.79  3.34 
Behavioral 0.55 1.11 2.25 2.30 2.41 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 892 of 1057
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  | 130 Applied Energy Group • www.appliedenergygroup.com
Table 6-38 Achievable DR Potential by Option for Idaho (Summer MW @Generator)
 2021 2022 2025 2030 2040 
Achievable Potential (MW)           
DLC Central AC 0.22 0.66 2.30 2.50 2.94 
DLC Water Heating 0.53  1.61  5.60  6.00  6.88 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling  0.22  0.66  2.30  2.50  2.94 
DLC Smart Appliances 0.10 0.30 1.04 1.10 1.24 
Third Party Contracts 0.57  2.01  7.55  7.57  7.64 
DLC Electric Vehicle Charging 0.00 0.02 0.09 0.19 0.39 
Time‐of‐Use Opt‐in 0.21  0.67  2.52  2.61  2.80 
Time‐of‐Use Opt‐out 10.37 9.65 9.80 10.09 10.74 
Variable Peak Pricing Rates 0.69  2.24  8.70  9.04  9.75 
Real Time Pricing 0.04 0.11 0.37 0.36 0.36 
Ancillary Services 0.74  0.74  0.76  0.79  0.85 
Thermal Energy Storage 0.00 0.03 0.31 0.32 0.34 
Battery Energy Storage 0.03  0.08  0.35  0.98  1.87 
Behavioral 0.26 0.52 1.06 1.11 1.21 
Cost Results
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 27.89
MW of savings in 2040 at $21.44/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of VPP deployment costs.
 The second lowest levelized cost option is the TOU Opt-in rate. It delivers 8.25 MW of savings in 2040
at $44.49/kW-year system wide.
Table 6-39 presents the levelized costs per kW of equivalent generation capacity over 2021-2040 for both
Washington and Idaho as well as the system weighted average levelized costs across both states. In
addition, we show the 2040 savings potential from DR options for reference purposes.
Key findings include:
 The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 27.89
MW of savings in 2040 at $21.44/kW-year system wide. Enabling technology purchase and installation
costs for enhancing customer response is a large part of VPP deployment costs.
 The second lowest levelized cost option is the TOU Opt-in rate. It delivers 8.25 MW of savings in 2040
at $44.49/kW-year system wide.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 893 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | 131 Applied Energy Group • www.appliedenergygroup.com
Table 6-39 DR Program Costs and Potential – Summer
DR Option 
Washington 2021‐
2040 
Levelized Cost 
($/kW‐year) 
Idaho 2021‐2040 
Levelized Cost 
($/kW‐year) 
System Weighted 
Average  
Levelized Cost 
($/kW‐year) 
System Summer 
Potential MW in 
2040 
DLC Central AC $120.31 $118.14 $119.55 8.00 
DLC Water Heating $139.94 $138.67 $139.49 19.27 
DLC Smart Thermostats ‐ Heating ‐ ‐ ‐ ‐ 
DLC Smart Thermostats ‐ Cooling $131.00 $127.06 $129.62 8.00 
DLC Smart Appliances $237.04 $240.63 $238.30 3.45 
Third Party Contracts $83.62 $82.98 $83.39 20.87 
DLC Electric Vehicle Charging $688.90 $698.35 $692.16 1.14 
Time‐of‐Use Opt‐in $44.49 $55.11 $48.03 8.25 
Time‐of‐Use Opt‐out $53.81 $68.96 $58.88 31.42 
Variable Peak Pricing Rates $20.87 $22.57 $21.44 27.89 
Real Time Pricing $117.58 $115.69 $116.90 0.65 
Ancillary Services $99.98 $104.78 $101.56 2.25 
Thermal Energy Storage $122.10 $131.73 $125.31 2.41 
Battery Energy Storage $593.83 $573.63 $585.74 0.84 
Behavioral $389.24 $393.20 $390.63 5.22 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 894 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 895 of 1057

| A‐1 Applied Energy Group • www.appliedenergygroup.com

MARKET PROFILES
This appendix presents the market profiles for each sector and segment for Washington, followed by
Idaho.
Begins on Next page.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 896 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐2 Applied Energy Group • www.appliedenergygroup.com
Table A-1 Washington Residential Single Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 38.4%  1,271 488  66.1 
Cooling Room AC 12.3% 691 85 11.5 
Cooling Air‐Source Heat Pump 19.4%  1,332 258  34.9 
Cooling Geothermal Heat Pump 1.0% 1,176 12 1.6 
Cooling Evaporative AC 1.3%  647 8  1.1 
Space Heating Electric Room Heat 6.3% 14,299 904 122.4 
Space Heating  Electric Furnace 7.4%  16,116  1,195  162.0 
Space Heating Air‐Source Heat Pump 19.4% 12,257 2,373 321.5 
Space Heating  Geothermal Heat Pump 1.0%  5,402 55  7.5 
Space Heating Secondary Heating 66.5% 372 248 33.6 
Water Heating  Water Heater <= 55 Gal  42.2%  3,362  1,419  192.3 
Water Heating Water Heater > 55 Gal 5.8% 3,554 205 27.8 
Interior Lighting  General Service Screw‐in  100.0%  761  761  103.1 
Interior Lighting Linear Lighting 100.0% 124 124 16.8 
Interior Lighting  Exempted Screw‐In 100.0%  58 58  7.8 
Exterior Lighting Screw‐in 100.0% 284 284 38.5 
Appliances Clothes Washer 96.4%  77 74  10.1 
Appliances Clothes Dryer 38.6% 741 286 38.8 
Appliances Dishwasher 80.9%  377 305  41.3 
Appliances Refrigerator 94.6% 705 667 90.4 
Appliances Freezer 59.1%  564 333  45.2 
Appliances Second Refrigerator 39.7% 829 329 44.6 
Appliances Stove/Oven 66.9%  443 296  40.2 
Appliances Microwave 95.6% 124 119 16.1 
Electronics Personal Computers 80.5%  161 130  17.5 
Electronics Monitor 161.4% 61 99 13.4 
Electronics Laptops 94.4%  42 40  5.4 
Electronics TVs 205.8% 114 234 31.7 
Electronics Printer/Fax/Copier 85.5%  42 36  4.9 
Electronics Set‐top Boxes/DVRs 175.4% 99 173 23.4 
Electronics Devices and Gadgets 100.0%  108 108  14.6 
Miscellaneous Electric Vehicles 0.2% 4,324 9 1.2 
Miscellaneous  Pool Pump 0.5%  3,500 19  2.5 
Miscellaneous Pool Heater 0.1% 3,517 5 0.7 
Miscellaneous  Hot Tub / Spa 0.7%  2,032 13  1.8 
Miscellaneous Furnace Fan 75.8% 205 156 21.1 
Miscellaneous  Well pump 2.0%  561 11  1.5 
Miscellaneous Miscellaneous 100.0% 1,554 1,554 210.5 
 Total       13,473  1,825.3 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 897 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐3 Applied Energy Group • www.appliedenergygroup.com
Table A-2 Washington Residential Multi Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 16.3%  426 70  0.9 
Cooling Room AC 49.0% 258 127 1.6 
Cooling Air‐Source Heat Pump 2.9%  426 12  0.2 
Cooling Geothermal Heat Pump 0.0% 376 0 0.0 
Cooling Evaporative AC 0.9%  320 3  0.0 
Space Heating Electric Room Heat 72.8% 2,937 2,139 26.7 
Space Heating  Electric Furnace 7.6%  3,143 239  3.0 
Space Heating Air‐Source Heat Pump 2.9% 1,831 53 0.7 
Space Heating  Geothermal Heat Pump 0.0%  807 0  0.0 
Space Heating Secondary Heating 44.8% 443 199 2.5 
Water Heating  Water Heater <= 55 Gal  74.2%  2,100  1,558  19.4 
Water Heating Water Heater > 55 Gal 0.5% 2,220 10 0.1 
Interior Lighting  General Service Screw‐in  100.0%  405  405  5.1 
Interior Lighting Linear Lighting 100.0% 33 33 0.4 
Interior Lighting  Exempted Screw‐In 100.0%  33 33  0.4 
Exterior Lighting Screw‐in 100.0% 130 130 1.6 
Appliances Clothes Washer 82.7%  75 62  0.8 
Appliances Clothes Dryer 69.1% 586 405 5.1 
Appliances Dishwasher 70.9%  375 266  3.3 
Appliances Refrigerator 92.7% 701 650 8.1 
Appliances Freezer 46.4%  562 261  3.3 
Appliances Second Refrigerator 3.9% 660 25 0.3 
Appliances Stove/Oven 74.5%  357 266  3.3 
Appliances Microwave 93.6% 124 117 1.5 
Electronics Personal Computers 35.5%  161 57  0.7 
Electronics Monitor 72.8% 61 45 0.6 
Electronics Laptops 41.9%  42 18  0.2 
Electronics TVs 124.7% 114 142 1.8 
Electronics Printer/Fax/Copier 49.5%  42 21  0.3 
Electronics Set‐top Boxes/DVRs 91.4% 99 90 1.1 
Electronics Devices and Gadgets 100.0%  108 108  1.3 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  2,032 0  0.0 
Miscellaneous Furnace Fan 18.9% 73 14 0.2 
Miscellaneous  Well pump 0.0%  556 0  0.0 
Miscellaneous Miscellaneous 100.0% 529 529 6.6 
 Total       8,084  100.9 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 898 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐4 Applied Energy Group • www.appliedenergygroup.com
Table A-3 Washington Residential Mobile Home Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 19.6%  1,001 196  1.6 
Cooling Room AC 18.5% 531 98 0.8 
Cooling Air‐Source Heat Pump 26.9%  1,001 269  2.2 
Cooling Geothermal Heat Pump 0.0% 881 0 0.0 
Cooling Evaporative AC 1.7%  499 9  0.1 
Space Heating Electric Room Heat 0.0% 7,208 0 0.0 
Space Heating  Electric Furnace 32.1%  7,715  2,478  19.9 
Space Heating Air‐Source Heat Pump 26.9% 6,752 1,813 14.5 
Space Heating  Geothermal Heat Pump 0.0%  3,094 0  0.0 
Space Heating Secondary Heating 54.2% 493 267 2.1 
Water Heating  Water Heater <= 55 Gal  67.3%  3,288  2,214  17.8 
Water Heating Water Heater > 55 Gal 0.0% 3,476 0 0.0 
Interior Lighting  General Service Screw‐in  100.0%  441  441  3.5 
Interior Lighting Linear Lighting 100.0% 62 62 0.5 
Interior Lighting  Exempted Screw‐In 100.0%  19 19  0.2 
Exterior Lighting Screw‐in 100.0% 109 109 0.9 
Appliances Clothes Washer 91.2%  77 70  0.6 
Appliances Clothes Dryer 66.7% 924 616 4.9 
Appliances Dishwasher 70.2%  377 265  2.1 
Appliances Refrigerator 93.0% 700 651 5.2 
Appliances Freezer 61.4%  565 347  2.8 
Appliances Second Refrigerator 18.2% 742 135 1.1 
Appliances Stove/Oven 82.5%  537 443  3.6 
Appliances Microwave 93.0% 124 116 0.9 
Electronics Personal Computers 45.8%  161 74  0.6 
Electronics Monitor 77.1% 61 47 0.4 
Electronics Laptops 66.7%  42 28  0.2 
Electronics TVs 156.3% 114 177 1.4 
Electronics Printer/Fax/Copier 58.3%  42 25  0.2 
Electronics Set‐top Boxes/DVRs 91.7% 99 90 0.7 
Electronics Devices and Gadgets 100.0%  108 108  0.9 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  2,032 0  0.0 
Miscellaneous Furnace Fan 84.6% 157 132 1.1 
Miscellaneous  Well pump 3.4%  451 15  0.1 
Miscellaneous Miscellaneous 100.0% 811 811 6.5 
 Total       12,125  97.3 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 899 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐5 Applied Energy Group • www.appliedenergygroup.com
Table A-4 Washington Residential Low-Income Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 18.9%  444 84  5.6 
Cooling Room AC 42.3% 255 108 7.2 
Cooling Air‐Source Heat Pump 6.9%  449 31  2.1 
Cooling Geothermal Heat Pump 0.1% 396 0 0.0 
Cooling Evaporative AC 1.0%  284 3  0.2 
Space Heating Electric Room Heat 58.9% 3,709 2,185 146.1 
Space Heating  Electric Furnace 10.0%  4,043 406  27.1 
Space Heating Air‐Source Heat Pump 6.9% 2,851 197 13.2 
Space Heating  Geothermal Heat Pump 0.1%  1,269 1  0.1 
Space Heating Secondary Heating 47.9% 337 162 10.8 
Water Heating  Water Heater <= 55 Gal  70.3%  1,993  1,401  93.7 
Water Heating Water Heater > 55 Gal 1.0% 2,107 20 1.3 
Interior Lighting  General Service Screw‐in  100.0%  441  441  29.5 
Interior Lighting Linear Lighting 100.0% 62 62 4.1 
Interior Lighting  Exempted Screw‐In 100.0% 19 19  1.3 
Exterior Lighting Screw‐in 100.0% 109 109 7.3 
Appliances Clothes Washer 84.9% 83 70  4.7 
Appliances Clothes Dryer 65.8% 734 483 32.3 
Appliances Dishwasher 71.8%  382 275  18.4 
Appliances Refrigerator 92.9% 707 658 44.0 
Appliances Freezer 49.1%  566 278  18.6 
Appliances Second Refrigerator 8.9% 685 61 4.1 
Appliances Stove/Oven 74.6%  438 327  21.8 
Appliances Microwave 93.8% 126 118 7.9 
Electronics Personal Computers 41.0%  163 67  4.5 
Electronics Monitor 82.1% 62 51 3.4 
Electronics Laptops 49.7% 43 21  1.4 
Electronics TVs 136.0% 115 156 10.4 
Electronics Printer/Fax/Copier 54.0% 43 23  1.5 
Electronics Set‐top Boxes/DVRs 99.8% 100 100 6.7 
Electronics Devices and Gadgets 100.0%  108 108  7.2 
Miscellaneous Electric Vehicles 0.0% 4,324 1 0.1 
Miscellaneous  Pool Pump 0.1%  3,500 2  0.1 
Miscellaneous Pool Heater 0.0% 3,517 1 0.0 
Miscellaneous  Hot Tub / Spa 0.1%  2,032 1  0.1 
Miscellaneous Furnace Fan 31.2% 95 30 2.0 
Miscellaneous  Well pump 0.5%  546 3  0.2 
Miscellaneous Miscellaneous 100.0% 668 668 44.6 
 Total       8,728  583.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 900 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐6 Applied Energy Group • www.appliedenergygroup.com
Table A-5 Washington Commercial Large Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 13.7% 3.08 0.42  11.9 
Cooling Water‐Cooled Chiller 8.5% 3.37 0.28 8.0 
Cooling RTU 44.5% 3.22 1.43  40.4 
Cooling PTAC 2.4% 3.80 0.09 2.5 
Cooling PTHP 0.7% 3.22 0.02  0.7 
Cooling Evaporative AC 0.0% 1.29 0.00 0.0 
Cooling Air‐Source Heat Pump 14.2% 3.22 0.46  12.9 
Cooling Geothermal Heat Pump 7.6% 1.96 0.15 4.2 
Heating Electric Furnace 1.2% 5.64 0.07  2.0 
Heating Electric Room Heat 23.8% 5.37 1.28 36.0 
Heating PTHP 0.7% 4.29 0.03  0.9 
Heating Air‐Source Heat Pump 14.2% 4.77 0.68 19.1 
Heating Geothermal Heat Pump 7.6% 3.85 0.29  8.3 
Ventilation Ventilation 100.0% 3.11 3.11 87.7 
Water Heating  Water Heater 45.2% 1.04 0.47  13.2 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 7.0 
Interior Lighting  Exempted Lighting 100.0% 0.10 0.10  2.9 
Interior Lighting High‐Bay Lighting 100.0% 1.01 1.01 28.4 
Interior Lighting  Linear Lighting 100.0% 1.72 1.72  48.6 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 2.7 
Exterior Lighting  Area Lighting 100.0% 1.28 1.28  36.0 
Exterior Lighting Linear Lighting 100.0% 0.18 0.18 5.1 
Refrigeration  Walk‐in Refrigerator/Freezer 2.0% 0.14 0.00  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 14.0% 0.03 0.00 0.1 
Refrigeration  Glass Door Display 77.4% 0.03 0.03  0.7 
Refrigeration  Open Display Case 77.4% 0.19 0.15 4.2 
Refrigeration  Icemaker 44.9% 0.05 0.02  0.7 
Refrigeration  Vending Machine 44.9% 0.05 0.02 0.6 
Food Preparation  Oven 66.0% 0.09 0.06  1.6 
Food Preparation Fryer 76.4% 0.13 0.10 2.7 
Food Preparation  Dishwasher 43.1% 0.18 0.08  2.1 
Food Preparation Hot Food Container 43.1% 0.02 0.01 0.3 
Food Preparation  Steamer 43.1% 0.13 0.06  1.6 
Office Equipment Desktop Computer 100.0% 2.35 2.35 66.1 
Office Equipment  Laptop 100.0% 0.36 0.36  10.2 
Office Equipment Server 100.0% 0.23 0.23 6.5 
Office Equipment  Monitor 100.0% 0.41 0.41  11.7 
Office Equipment Printer/Copier/Fax 100.0% 0.21 0.21 6.0 
Office Equipment  POS Terminal 40.0% 0.03 0.01  0.3 
Miscellaneous Non‐HVAC Motors 89.6% 0.35 0.31 8.8 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.42  1.42  39.9 
Total       19.27 542.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 901 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐7 Applied Energy Group • www.appliedenergygroup.com
Table A-6 Washington Commercial Small Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.17 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.45 0.00 0.0 
Cooling RTU 65.6% 3.61 2.37  28.0 
Cooling PTAC 2.3% 4.25 0.10 1.2 
Cooling PTHP 0.7% 3.61 0.03  0.3 
Cooling Evaporative AC 0.0% 1.44 0.00 0.0 
Cooling Air‐Source Heat Pump 14.0% 3.61 0.50  6.0 
Cooling Geothermal Heat Pump 7.5% 2.20 0.16 1.9 
Heating Electric Furnace 1.1% 6.82 0.08  0.9 
Heating Electric Room Heat 21.9% 6.49 1.42 16.8 
Heating PTHP 0.7% 5.16 0.04  0.4 
Heating Air‐Source Heat Pump 14.0% 5.73 0.80 9.5 
Heating Geothermal Heat Pump 7.5% 4.44 0.33  3.9 
Ventilation Ventilation 100.0% 1.25 1.25 14.7 
Water Heating  Water Heater 60.0% 0.94 0.56  6.6 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 2.9 
Interior Lighting  Exempted Lighting 100.0% 0.13 0.13  1.6 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 17.8 
Interior Lighting  Linear Lighting 100.0% 1.54 1.54  18.2 
Exterior Lighting General Service Lighting 100.0% 0.16 0.16 1.9 
Exterior Lighting  Area Lighting 100.0% 1.58 1.58  18.6 
Exterior Lighting Linear Lighting 100.0% 0.07 0.07 0.9 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.66  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 8.8% 0.15 0.01 0.2 
Refrigeration   Glass Door Display 0.0% 0.15 0.00  0.0 
Refrigeration  Open Display Case 0.0% 0.90 0.00 0.0 
Refrigeration   Icemaker 5.1% 0.25 0.01  0.2 
Refrigeration  Vending Machine 5.1% 0.12 0.01 0.1 
Food Preparation  Oven 3.6% 0.19 0.01  0.1 
Food Preparation Fryer 3.6% 0.27 0.01 0.1 
Food Preparation  Dishwasher 3.6% 0.37 0.01  0.2 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.27 0.01  0.1 
Office Equipment Desktop Computer 100.0% 1.24 1.24 14.7 
Office Equipment  Laptop 100.0% 0.19 0.19  2.3 
Office Equipment Server 100.0% 0.36 0.36 4.3 
Office Equipment  Monitor 100.0% 0.22 0.22  2.6 
Office Equipment Printer/Copier/Fax 100.0% 0.17 0.17 2.0 
Office Equipment  POS Terminal 20.0% 0.10 0.02  0.2 
Miscellaneous Non‐HVAC Motors 22.0% 0.28 0.06 0.7 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.19  1.19  14.0 
Total       16.41 193.9 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 902 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐8 Applied Energy Group • www.appliedenergygroup.com
Table A-7 Washington Commercial Retail Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 2.19 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 2.39 0.00 0.0 
Cooling RTU 67.0% 2.50 1.67  36.6 
Cooling PTAC 2.4% 2.62 0.06 1.4 
Cooling PTHP 0.8% 2.49 0.02  0.4 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 14.3% 2.49 0.36  7.8 
Cooling Geothermal Heat Pump 7.7% 1.52 0.12 2.5 
Heating Electric Furnace 0.5% 6.04 0.03  0.7 
Heating Electric Room Heat 9.6% 5.75 0.55 12.1 
Heating PTHP 0.8% 4.03 0.03  0.7 
Heating Air‐Source Heat Pump 14.3% 4.47 0.64 14.0 
Heating Geothermal Heat Pump 7.7% 3.04 0.23  5.1 
Ventilation Ventilation 100.0% 1.01 1.01 22.1 
Water Heating  Water Heater 61.8% 0.82 0.50  11.0 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 8.3 
Interior Lighting  Exempted Lighting 100.0% 0.36 0.36  7.9 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 33.1 
Interior Lighting  Linear Lighting 100.0% 2.28 2.28  49.9 
Exterior Lighting General Service Lighting 100.0% 0.24 0.24 5.2 
Exterior Lighting  Area Lighting 100.0% 0.84 0.84  18.5 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 1.7 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.42  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 5.4% 0.09 0.01 0.1 
Refrigeration   Glass Door Display 5.4% 0.10 0.01  0.1 
Refrigeration  Open Display Case 5.4% 0.57 0.03 0.7 
Refrigeration   Icemaker 5.1% 0.32 0.02  0.4 
Refrigeration  Vending Machine 5.1% 0.15 0.01 0.2 
Food Preparation  Oven 3.6% 0.17 0.01  0.1 
Food Preparation Fryer 3.6% 0.25 0.01 0.2 
Food Preparation  Dishwasher 3.6% 0.35 0.01  0.3 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.25 0.01  0.2 
Office Equipment Desktop Computer 100.0% 0.18 0.18 3.9 
Office Equipment  Laptop 100.0% 0.03 0.03  0.6 
Office Equipment Server 82.0% 0.21 0.17 3.8 
Office Equipment  Monitor 100.0% 0.03 0.03  0.7 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.4 
Office Equipment  POS Terminal 100.0% 0.06 0.06  1.2 
Miscellaneous Non‐HVAC Motors 40.2% 0.34 0.13 3.0 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 7.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 4.0% 0.03 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.43  1.43  31.4 
Total       13.09 286.3 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 903 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐9 Applied Energy Group • www.appliedenergygroup.com
Table A-8 Washington Commercial Restaurant Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.49 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.52 0.00 0.0 
Cooling RTU 72.9% 3.99 2.91  7.7 
Cooling PTAC 2.7% 4.69 0.13 0.3 
Cooling PTHP 1.9% 3.98 0.08  0.2 
Cooling Evaporative AC 3.3% 1.59 0.05 0.1 
Cooling Air‐Source Heat Pump 8.2% 3.98 0.33  0.9 
Cooling Geothermal Heat Pump 0.0% 2.43 0.00 0.0 
Heating Electric Furnace 19.1% 4.81 0.92  2.4 
Heating Electric Room Heat 1.7% 4.58 0.08 0.2 
Heating PTHP 1.9% 3.01 0.06  0.2 
Heating Air‐Source Heat Pump 8.2% 3.35 0.28 0.7 
Heating Geothermal Heat Pump 0.0% 2.37 0.00  0.0 
Ventilation Ventilation 100.0% 1.98 1.98 5.2 
Water Heating  Water Heater 57.9% 7.75 4.49  11.9 
Interior Lighting General Service Lighting 100.0% 1.34 1.34 3.5 
Interior Lighting  Exempted Lighting 100.0% 0.94 0.94  2.5 
Interior Lighting High‐Bay Lighting 100.0% 2.92 2.92 7.7 
Interior Lighting  Linear Lighting 100.0% 1.87 1.87  4.9 
Exterior Lighting General Service Lighting 100.0% 0.28 0.28 0.7 
Exterior Lighting  Area Lighting 100.0% 2.14 2.14  5.7 
Exterior Lighting Linear Lighting 100.0% 0.40 0.40 1.1 
Refrigeration   Walk‐in Refrigerator/Freezer  74.0%  6.59  4.88  12.9 
Refrigeration  Reach‐in Refrigerator/Freezer 7.0% 2.96 0.21 0.5 
Refrigeration   Glass Door Display 5.2% 1.52 0.08  0.2 
Refrigeration  Open Display Case 5.2% 9.00 0.47 1.2 
Refrigeration   Icemaker 97.3% 2.49 2.42  6.4 
Refrigeration  Vending Machine 97.3% 1.17 1.14 3.0 
Food Preparation  Oven 21.0% 3.95 0.83  2.2 
Food Preparation Fryer 82.0% 5.71 4.68 12.4 
Food Preparation  Dishwasher 52.5% 3.93 2.06  5.5 
Food Preparation Hot Food Container 84.0% 0.54 0.45 1.2 
Food Preparation  Steamer 16.0% 2.88 0.46  1.2 
Office Equipment Desktop Computer 100.0% 0.29 0.29 0.8 
Office Equipment  Laptop 100.0% 0.04 0.04  0.1 
Office Equipment Server 50.0% 0.34 0.17 0.5 
Office Equipment  Monitor 100.0% 0.05 0.05  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.2 
Office Equipment  POS Terminal 100.0% 0.09 0.09  0.2 
Miscellaneous Non‐HVAC Motors 20.0% 0.54 0.11 0.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  2.15  2.15  5.7 
Total       41.80 110.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 904 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐10 Applied Energy Group • www.appliedenergygroup.com
Table A-9 Washington Commercial Grocery Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.5% 3.98 0.02  0.1 
Cooling Water‐Cooled Chiller 0.3% 4.33 0.01 0.1 
Cooling RTU 71.3% 4.53 3.23  13.8 
Cooling PTAC 2.1% 5.33 0.11 0.5 
Cooling PTHP 0.6% 4.15 0.03  0.1 
Cooling Evaporative AC 1.2% 1.81 0.02 0.1 
Cooling Air‐Source Heat Pump 7.2% 4.15 0.30  1.3 
Cooling Geothermal Heat Pump 0.0% 1.41 0.00 0.0 
Heating Electric Furnace 6.4% 7.41 0.47  2.0 
Heating Electric Room Heat 1.2% 7.06 0.08 0.4 
Heating PTHP 0.6% 3.42 0.02  0.1 
Heating Air‐Source Heat Pump 7.2% 3.80 0.27 1.2 
Heating Geothermal Heat Pump 0.0% 2.65 0.00  0.0 
Ventilation Ventilation 100.0% 2.18 2.18 9.3 
Water Heating  Water Heater 62.5% 2.29 1.43  6.1 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 1.6 
Interior Lighting  Exempted Lighting 100.0% 0.30 0.30  1.3 
Interior Lighting High‐Bay Lighting 100.0% 2.02 2.02 8.6 
Interior Lighting  Linear Lighting 100.0% 5.01 5.01  21.4 
Exterior Lighting General Service Lighting 100.0% 0.36 0.36 1.5 
Exterior Lighting  Area Lighting 100.0% 1.78 1.78  7.6 
Exterior Lighting Linear Lighting 100.0% 0.38 0.38 1.6 
Refrigeration   Walk‐in Refrigerator/Freezer  16.0%  5.38  0.86  3.7 
Refrigeration  Reach‐in Refrigerator/Freezer 83.1% 0.34 0.29 1.2 
Refrigeration   Glass Door Display 94.9% 3.54 3.36  14.3 
Refrigeration  Open Display Case 94.9% 20.97 19.90 84.9 
Refrigeration   Icemaker 98.9% 0.29 0.29  1.2 
Refrigeration  Vending Machine 98.9% 0.27 0.27 1.1 
Food Preparation  Oven 11.0% 0.64 0.07  0.3 
Food Preparation Fryer 87.0% 0.92 0.80 3.4 
Food Preparation  Dishwasher 54.9% 1.27 0.70  3.0 
Food Preparation Hot Food Container 73.0% 0.17 0.13 0.5 
Food Preparation  Steamer 20.0% 0.93 0.19  0.8 
Office Equipment Desktop Computer 100.0% 0.16 0.16 0.7 
Office Equipment  Laptop 64.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.09 0.09 0.4 
Office Equipment  Monitor 100.0% 0.03 0.03  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.1 
Office Equipment  POS Terminal 100.0% 0.06 0.06  0.3 
Miscellaneous Non‐HVAC Motors 34.6% 0.20 0.07 0.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous 100.0% 0.63 0.63  2.7 
Total       46.35 197.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 905 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐11 Applied Energy Group • www.appliedenergygroup.com
Table A-10 Washington Commercial Health Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 16.7% 5.60 0.93  4.6 
Cooling Water‐Cooled Chiller 66.7% 7.13 4.76 23.3 
Cooling RTU 11.0% 5.57 0.61  3.0 
Cooling PTAC 0.4% 6.56 0.03 0.1 
Cooling PTHP 0.0% 5.56 0.00  0.0 
Cooling Evaporative AC 0.0% 2.23 0.00 0.0 
Cooling Air‐Source Heat Pump 0.6% 5.56 0.03  0.2 
Cooling Geothermal Heat Pump 0.9% 3.38 0.03 0.1 
Heating Electric Furnace 3.0%  17.22 0.51  2.5 
Heating Electric Room Heat 0.1% 16.40 0.01 0.0 
Heating PTHP 0.0%  10.10 0.00  0.0 
Heating Air‐Source Heat Pump 0.6% 11.22 0.06 0.3 
Heating Geothermal Heat Pump 0.9% 7.92 0.07  0.3 
Ventilation Ventilation 100.0% 4.56 4.56 22.3 
Water Heating  Water Heater 12.6% 4.56 0.57  2.8 
Interior Lighting General Service Lighting 100.0% 0.55 0.55 2.7 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  1.1 
Interior Lighting High‐Bay Lighting 100.0% 2.59 2.59 12.7 
Interior Lighting  Linear Lighting 100.0% 4.04 4.04  19.8 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.2 
Exterior Lighting  Area Lighting 100.0% 0.66 0.66  3.3 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.4 
Refrigeration   Walk‐in Refrigerator/Freezer  33.0%  0.27  0.09  0.4 
Refrigeration  Reach‐in Refrigerator/Freezer 50.0% 0.06 0.03 0.2 
Refrigeration   Glass Door Display 90.4% 0.06 0.06  0.3 
Refrigeration  Open Display Case 90.4% 0.38 0.34 1.7 
Refrigeration   Icemaker 90.4% 0.21 0.19  0.9 
Refrigeration  Vending Machine 90.4% 0.10 0.09 0.4 
Food Preparation  Oven 69.7% 0.64 0.45  2.2 
Food Preparation Fryer 80.7% 0.93 0.75 3.7 
Food Preparation  Dishwasher 53.5% 1.28 0.68  3.3 
Food Preparation Hot Food Container 53.5% 0.17 0.09 0.5 
Food Preparation  Steamer 53.5% 0.93 0.50  2.4 
Office Equipment Desktop Computer 100.0% 0.56 0.56 2.7 
Office Equipment  Laptop 100.0% 0.03 0.03  0.2 
Office Equipment Server 100.0% 0.07 0.07 0.3 
Office Equipment  Monitor 100.0% 0.10 0.10  0.5 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.3 
Office Equipment  POS Terminal 100.0% 0.04 0.04  0.2 
Miscellaneous Non‐HVAC Motors 74.1% 0.63 0.47 2.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 63.0% 0.04 0.02  0.1 
Miscellaneous Clothes Dryer 58.0% 0.12 0.07 0.3 
Miscellaneous  Other Miscellaneous  100.0%  4.89  4.89  23.9 
Total       29.95 146.7 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 906 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐12 Applied Energy Group • www.appliedenergygroup.com
Table A-11 Washington Commercial College Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 28.5% 4.25 1.21  8.2 
Cooling Water‐Cooled Chiller 0.0% 5.34 0.00 0.0 
Cooling RTU 46.8% 2.49 1.16  7.9 
Cooling PTAC 3.0% 2.93 0.09 0.6 
Cooling PTHP 2.1% 2.48 0.05  0.4 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 7.9% 2.48 0.20  1.3 
Cooling Geothermal Heat Pump 5.7% 1.51 0.09 0.6 
Heating Electric Furnace 0.0%  11.87 0.00  0.0 
Heating Electric Room Heat 8.1% 11.31 0.91 6.2 
Heating PTHP 2.1% 7.12 0.15  1.0 
Heating Air‐Source Heat Pump 7.9% 7.92 0.63 4.2 
Heating Geothermal Heat Pump 5.7% 5.95 0.34  2.3 
Ventilation Ventilation 100.0% 1.52 1.52 10.3 
Water Heating  Water Heater 55.3% 2.08 1.15  7.8 
Interior Lighting General Service Lighting 100.0% 0.09 0.09 0.6 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.3 
Interior Lighting High‐Bay Lighting 100.0% 1.42 1.42 9.6 
Interior Lighting  Linear Lighting 100.0% 2.19 2.19  14.8 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.1 
Exterior Lighting  Area Lighting 100.0% 0.29 0.29  1.9 
Exterior Lighting Linear Lighting 100.0% 0.75 0.75 5.1 
Refrigeration   Walk‐in Refrigerator/Freezer  7.7%  0.16  0.01  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 13.4% 0.07 0.01 0.1 
Refrigeration   Glass Door Display 26.6% 0.04 0.01  0.1 
Refrigeration  Open Display Case 26.6% 0.22 0.06 0.4 
Refrigeration   Icemaker 26.6% 0.12 0.03  0.2 
Refrigeration  Vending Machine 26.6% 0.06 0.02 0.1 
Food Preparation  Oven 21.0% 0.24 0.05  0.3 
Food Preparation Fryer 21.0% 0.34 0.07 0.5 
Food Preparation  Dishwasher 21.0% 0.47 0.10  0.7 
Food Preparation Hot Food Container 21.0% 0.06 0.01 0.1 
Food Preparation  Steamer 21.0% 0.35 0.07  0.5 
Office Equipment Desktop Computer 100.0% 0.47 0.47 3.2 
Office Equipment  Laptop 100.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.06 0.06 0.4 
Office Equipment  Monitor 100.0% 0.08 0.08  0.6 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.4 
Office Equipment  POS Terminal 100.0% 0.02 0.02  0.1 
Miscellaneous Non‐HVAC Motors 88.8% 0.08 0.07 0.5 
Miscellaneous  Pool Pump 90.3% 0.01 0.01  0.1 
Miscellaneous Pool Heater 36.2% 0.02 0.01 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.01 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.35  0.35  2.4 
Total       13.91 93.9 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 907 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐13 Applied Energy Group • www.appliedenergygroup.com
Table A-12 Washington Commercial School Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 22.1% 1.97 0.43  6.7 
Cooling Water‐Cooled Chiller 0.0% 2.47 0.00 0.0 
Cooling RTU 36.2% 1.15 0.42  6.4 
Cooling PTAC 2.4% 1.35 0.03 0.5 
Cooling PTHP 1.6% 1.15 0.02  0.3 
Cooling Evaporative AC 0.0% 0.46 0.00 0.0 
Cooling Air‐Source Heat Pump 6.1% 1.15 0.07  1.1 
Cooling Geothermal Heat Pump 4.4% 0.70 0.03 0.5 
Heating Electric Furnace 0.0% 6.44 0.00  0.0 
Heating Electric Room Heat 4.4% 6.13 0.27 4.2 
Heating PTHP 1.6% 3.86 0.06  1.0 
Heating Air‐Source Heat Pump 6.1% 4.29 0.26 4.1 
Heating Geothermal Heat Pump 4.4% 3.23 0.14  2.2 
Ventilation Ventilation 100.0% 0.71 0.71 11.0 
Water Heating  Water Heater 50.0% 0.99 0.50  7.6 
Interior Lighting General Service Lighting 100.0% 0.16 0.16 2.5 
Interior Lighting  Exempted Lighting 100.0% 0.18 0.18  2.8 
Interior Lighting High‐Bay Lighting 100.0% 0.81 0.81 12.5 
Interior Lighting  Linear Lighting 100.0% 1.51 1.51  23.3 
Exterior Lighting General Service Lighting 100.0% 0.00 0.00 0.1 
Exterior Lighting  Area Lighting 100.0% 0.12 0.12  1.8 
Exterior Lighting Linear Lighting 100.0% 0.66 0.66 10.1 
Refrigeration   Walk‐in Refrigerator/Freezer  19.0%  0.17  0.03  0.5 
Refrigeration  Reach‐in Refrigerator/Freezer 33.0% 0.08 0.02 0.4 
Refrigeration   Glass Door Display 65.7% 0.04 0.03  0.4 
Refrigeration  Open Display Case 65.7% 0.23 0.15 2.3 
Refrigeration   Icemaker 65.7% 0.13 0.08  1.3 
Refrigeration  Vending Machine 65.7% 0.06 0.04 0.6 
Food Preparation  Oven 64.8% 0.11 0.07  1.1 
Food Preparation Fryer 58.6% 0.16 0.09 1.5 
Food Preparation  Dishwasher 52.3% 0.22 0.12  1.8 
Food Preparation Hot Food Container 52.3% 0.03 0.02 0.2 
Food Preparation  Steamer 52.3% 0.16 0.08  1.3 
Office Equipment Desktop Computer 100.0% 0.29 0.29 4.5 
Office Equipment  Laptop 100.0% 0.02 0.02  0.3 
Office Equipment Server 100.0% 0.07 0.07 1.1 
Office Equipment  Monitor 100.0% 0.05 0.05  0.8 
Office Equipment Printer/Copier/Fax 100.0% 0.03 0.03 0.5 
Office Equipment  POS Terminal 36.0% 0.01 0.00  0.1 
Miscellaneous Non‐HVAC Motors 43.7% 0.07 0.03 0.5 
Miscellaneous  Pool Pump 6.0% 0.02 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.02 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.33  0.33  5.0 
Total       7.96 122.7 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 908 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐14 Applied Energy Group • www.appliedenergygroup.com
Table A-13 Washington Commercial Lodging Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 2.0% 0.49 0.01  0.1 
Cooling Water‐Cooled Chiller 7.3% 0.62 0.05 0.3 
Cooling RTU 15.8% 1.52 0.24  1.6 
Cooling PTAC 38.8% 1.79 0.70 4.7 
Cooling PTHP 13.0% 1.52 0.20  1.3 
Cooling Evaporative AC 0.5% 0.61 0.00 0.0 
Cooling Air‐Source Heat Pump 5.1% 1.52 0.08  0.5 
Cooling Geothermal Heat Pump 5.5% 1.44 0.08 0.5 
Heating Electric Furnace 1.4% 3.02 0.04  0.3 
Heating Electric Room Heat 51.1% 2.88 1.47 9.9 
Heating PTHP 13.0% 2.42 0.32  2.1 
Heating Air‐Source Heat Pump 5.1% 2.69 0.14 0.9 
Heating Geothermal Heat Pump 5.5% 1.90 0.10  0.7 
Ventilation Ventilation 100.0% 0.94 0.94 6.4 
Water Heating  Water Heater 50.0% 3.20 1.60  10.8 
Interior Lighting General Service Lighting 100.0% 0.81 0.81 5.4 
Interior Lighting  Exempted Lighting 100.0% 0.43 0.43  2.9 
Interior Lighting High‐Bay Lighting 100.0% 1.29 1.29 8.7 
Interior Lighting  Linear Lighting 100.0% 0.46 0.46  3.1 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.3 
Exterior Lighting  Area Lighting 100.0% 1.73 1.73  11.6 
Exterior Lighting Linear Lighting 100.0% 0.03 0.03 0.2 
Refrigeration   Walk‐in Refrigerator/Freezer  3.0%  0.39  0.01  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 19.0% 0.09 0.02 0.1 
Refrigeration   Glass Door Display 58.9% 0.09 0.05  0.4 
Refrigeration  Open Display Case 58.9% 0.54 0.32 2.1 
Refrigeration   Icemaker 58.9% 0.15 0.09  0.6 
Refrigeration  Vending Machine 58.9% 0.14 0.08 0.6 
Food Preparation  Oven 13.8% 0.26 0.04  0.2 
Food Preparation Fryer 21.0% 0.37 0.08 0.5 
Food Preparation  Dishwasher 30.0% 0.51 0.15  1.0 
Food Preparation Hot Food Container 30.0% 0.07 0.02 0.1 
Food Preparation  Steamer 30.0% 0.38 0.11  0.8 
Office Equipment Desktop Computer 100.0% 0.08 0.08 0.6 
Office Equipment  Laptop 100.0% 0.01 0.01  0.1 
Office Equipment Server 100.0% 0.05 0.05 0.3 
Office Equipment  Monitor 100.0% 0.01 0.01  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.1 
Office Equipment  POS Terminal 58.0% 0.01 0.01  0.1 
Miscellaneous Non‐HVAC Motors 91.3% 0.14 0.12 0.8 
Miscellaneous  Pool Pump 76.0% 0.01 0.01  0.1 
Miscellaneous Pool Heater 27.0% 0.02 0.00 0.0 
Miscellaneous  Clothes Washer 67.0% 0.02 0.01  0.1 
Miscellaneous Clothes Dryer 26.0% 0.07 0.02 0.1 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  4.2 
Total       12.69 85.3 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 909 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐15 Applied Energy Group • www.appliedenergygroup.com
Table A-14 Washington Commercial Warehouse Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 1.59 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 1.68 0.00 0.0 
Cooling RTU 16.0% 1.78 0.28  5.5 
Cooling PTAC 1.1% 2.09 0.02 0.4 
Cooling PTHP 0.3% 1.78 0.01  0.1 
Cooling Evaporative AC 0.0% 0.71 0.00 0.0 
Cooling Air‐Source Heat Pump 1.7% 1.78 0.03  0.6 
Cooling Geothermal Heat Pump 0.0% 1.08 0.00 0.0 
Heating Electric Furnace 2.3% 7.84 0.18  3.5 
Heating Electric Room Heat 12.4% 7.46 0.93 17.8 
Heating PTHP 0.3% 6.19 0.02  0.4 
Heating Air‐Source Heat Pump 1.7% 6.88 0.12 2.2 
Heating Geothermal Heat Pump 0.0% 5.93 0.00  0.0 
Ventilation Ventilation 100.0% 0.26 0.26 5.0 
Water Heating  Water Heater 55.3% 0.26 0.15  2.8 
Interior Lighting General Service Lighting 100.0% 0.07 0.07 1.4 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.7 
Interior Lighting High‐Bay Lighting 100.0% 1.69 1.69 32.6 
Interior Lighting  Linear Lighting 100.0% 0.28 0.28  5.4 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.4 
Exterior Lighting  Area Lighting 100.0% 0.38 0.38  7.3 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 1.5 
Refrigeration   Walk‐in Refrigerator/Freezer  1.1%  0.49  0.01  0.1 
Refrigeration  Reach‐in Refrigerator/Freezer 2.0% 0.11 0.00 0.0 
Refrigeration   Glass Door Display 10.1% 0.11 0.01  0.2 
Refrigeration  Open Display Case 10.1% 0.67 0.07 1.3 
Refrigeration   Icemaker 10.1% 0.19 0.02  0.4 
Refrigeration  Vending Machine 10.1% 0.09 0.01 0.2 
Food Preparation  Oven 2.3% 0.03 0.00  0.0 
Food Preparation Fryer 2.3% 0.05 0.00 0.0 
Food Preparation  Dishwasher 2.3% 0.07 0.00  0.0 
Food Preparation Hot Food Container 2.3% 0.01 0.00 0.0 
Food Preparation  Steamer 2.3% 0.05 0.00  0.0 
Office Equipment Desktop Computer 100.0% 0.09 0.09 1.7 
Office Equipment  Laptop 100.0% 0.01 0.01  0.2 
Office Equipment Server 89.0% 0.10 0.09 1.8 
Office Equipment  Monitor 100.0% 0.02 0.02  0.3 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.2 
Office Equipment  POS Terminal 77.0% 0.03 0.02  0.4 
Miscellaneous Non‐HVAC Motors 49.9% 0.12 0.06 1.2 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.43  0.43  8.3 
Total       5.40 104.0 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 910 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐16 Applied Energy Group • www.appliedenergygroup.com
Table A-15 Washington Commercial Miscellaneous Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 9.7% 1.64 0.16  4.8 
Cooling Water‐Cooled Chiller 5.0% 1.78 0.09 2.7 
Cooling RTU 56.8% 1.86 1.06  32.0 
Cooling PTAC 5.1% 2.19 0.11 3.4 
Cooling PTHP 2.6% 1.86 0.05  1.5 
Cooling Evaporative AC 0.0% 0.74 0.00 0.0 
Cooling Air‐Source Heat Pump 5.5% 1.86 0.10  3.1 
Cooling Geothermal Heat Pump 1.0% 1.13 0.01 0.4 
Heating Electric Furnace 12.5% 4.77 0.59  18.0 
Heating Electric Room Heat 14.8% 4.55 0.67 20.3 
Heating PTHP 2.6% 3.61 0.09  2.8 
Heating Air‐Source Heat Pump 5.5% 4.01 0.22 6.7 
Heating Geothermal Heat Pump 1.0% 3.13 0.03  1.0 
Ventilation Ventilation 100.0% 0.73 0.73 22.1 
Water Heating  Water Heater 53.0% 1.39 0.74  22.3 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 11.4 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  6.9 
Interior Lighting High‐Bay Lighting 100.0% 1.56 1.56 47.2 
Interior Lighting  Linear Lighting 100.0% 1.46 1.46  44.3 
Exterior Lighting General Service Lighting 100.0% 0.09 0.09 2.8 
Exterior Lighting  Area Lighting 100.0% 0.64 0.64  19.3 
Exterior Lighting Linear Lighting 100.0% 0.06 0.06 1.8 
Refrigeration   Walk‐in Refrigerator/Freezer  10.3%  0.58  0.06  1.8 
Refrigeration  Reach‐in Refrigerator/Freezer 12.1% 0.13 0.02 0.5 
Refrigeration   Glass Door Display 3.4% 0.13 0.00  0.1 
Refrigeration  Open Display Case 3.4% 0.79 0.03 0.8 
Refrigeration   Icemaker 21.6% 0.22 0.05  1.4 
Refrigeration  Vending Machine 21.6% 0.20 0.04 1.3 
Food Preparation  Oven 58.9% 0.08 0.05  1.5 
Food Preparation Fryer 29.9% 0.12 0.04 1.1 
Food Preparation  Dishwasher 15.4% 0.17 0.03  0.8 
Food Preparation Hot Food Container 15.4% 0.02 0.00 0.1 
Food Preparation  Steamer 15.4% 0.12 0.02  0.6 
Office Equipment Desktop Computer 100.0% 0.20 0.20 6.0 
Office Equipment  Laptop 100.0% 0.03 0.03  0.9 
Office Equipment Server 66.0% 0.12 0.08 2.3 
Office Equipment  Monitor 100.0% 0.03 0.03  1.1 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.7 
Office Equipment  POS Terminal 28.0% 0.03 0.01  0.3 
Miscellaneous Non‐HVAC Motors 59.9% 0.15 0.09 2.6 
Miscellaneous  Pool Pump 4.0% 0.01 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 10.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous 100.0% 0.57 0.57  17.1 
Total       10.43 315.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 911 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐17 Applied Energy Group • www.appliedenergygroup.com
Table A-16 Washington Industrial Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  6,629.79 165.74  2.8 
Cooling Water‐Cooled Chiller 2.5% 6,983.13 174.58 2.9 
Cooling RTU 11.4%  7,389.72 842.74  14.2 
Cooling Air‐Source Heat Pump 1.7% 7,386.34 124.90 2.1 
Cooling Geothermal Heat Pump 0.0%  4,926.69 0.00  0.0 
Heating Electric Furnace 2.3% 32,574.73 747.28 12.6 
Heating Electric Room Heat 12.4%  31,023.55 3,849.55  65.0 
Heating Air‐Source Heat Pump 1.7% 28,604.84 483.71 8.2 
Heating Geothermal Heat Pump 0.0%  19,079.43 0.00  0.0 
Ventilation Ventilation 100.0% 1,077.71 1,077.71 18.2 
Interior Lighting  General Service Lighting  100.0%  206.68  206.68  3.5 
Interior Lighting High‐Bay Lighting 100.0% 3,233.38 3,233.38 54.6 
Interior Lighting  Linear Lighting 100.0%  537.49 537.49  9.1 
Exterior Lighting General Service Lighting 100.0% 38.05 38.05 0.6 
Exterior Lighting  Area Lighting 100.0%  720.88 720.88  12.2 
Exterior Lighting Linear Lighting 100.0% 147.69 147.69 2.5 
Motors Pumps 100.0%  1,899.28 1,899.28  32.1 
Motors Fans & Blowers 100.0% 2,280.92 2,280.92 38.5 
Motors Compressed Air 100.0%  1,844.32 1,844.32  31.2 
Motors Material Handling 100.0% 3,900.92 3,900.92 65.9 
Motors Other Motors 100.0%  65.46 65.46  1.1 
Process Process Heating 100.0% 3,211.52 3,211.52 54.3 
Process Process Cooling 100.0%  843.19 843.19  14.2 
Process Process Refrigeration 100.0% 843.19 843.19 14.2 
Process Process Electrochemical 100.0%  324.59 324.59  5.5 
Process Process Other 100.0% 352.25 352.25 6.0 
Miscellaneous  Miscellaneous 100.0%  1,937.76 1,937.76  32.7 
Total       29,853.79 504.4 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 912 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐18 Applied Energy Group • www.appliedenergygroup.com
Table A-17 Idaho Residential Single Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 36.0%  1,271 458  31.2 
Cooling Room AC 11.6% 691 80 5.5 
Cooling Air‐Source Heat Pump 9.9%  1,332 132  9.0 
Cooling Geothermal Heat Pump 0.8% 1,176 10 0.7 
Cooling Evaporative AC 1.6%  647 10  0.7 
Space Heating Electric Room Heat 9.8% 15,052 1,470 100.1 
Space Heating  Electric Furnace 7.4%  16,964  1,262  86.0 
Space Heating Air‐Source Heat Pump 9.9% 12,902 1,277 87.0 
Space Heating  Geothermal Heat Pump 0.8%  5,686 47  3.2 
Space Heating Secondary Heating 57.2% 392 224 15.3 
Water Heating  Water Heater <= 55 Gal  43.0%  3,362  1,445  98.4 
Water Heating Water Heater > 55 Gal 5.9% 3,554 209 14.2 
Interior Lighting  General Service Screw‐in  100.0%  761  761  51.8 
Interior Lighting Linear Lighting 100.0% 124 124 8.4 
Interior Lighting  Exempted Screw‐In 100.0% 58 58  3.9 
Exterior Lighting Screw‐in 100.0% 284 284 19.4 
Appliances Clothes Washer 95.5% 83 79  5.4 
Appliances Clothes Dryer 65.6% 734 482 32.8 
Appliances Dishwasher 80.1%  382 306  20.8 
Appliances Refrigerator 95.5% 707 676 46.0 
Appliances Freezer 66.3%  566 376  25.6 
Appliances Second Refrigerator 39.7% 829 329 22.4 
Appliances Stove/Oven 58.4%  438 256  17.4 
Appliances Microwave 93.1% 126 117 8.0 
Electronics Personal Computers 63.3%  163 103  7.0 
Electronics Monitor 126.9% 62 79 5.4 
Electronics Laptops 85.7% 43 36  2.5 
Electronics TVs 199.0% 115 228 15.5 
Electronics Printer/Fax/Copier 76.9% 43 33  2.2 
Electronics Set‐top Boxes/DVRs 105.8% 100 105 7.2 
Electronics Devices and Gadgets 100.0%  108 108  7.3 
Miscellaneous Electric Vehicles 0.2% 4,324 9 0.6 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.8%  950 8  0.5 
Miscellaneous Furnace Fan 70.2% 541 380 25.9 
Miscellaneous  Well pump 0.0%  561 0  0.0 
Miscellaneous Miscellaneous 100.0% 1,254 1,254 85.4 
 Total       12,815  872.7 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 913 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐19 Applied Energy Group • www.appliedenergygroup.com
Table A-18 Idaho Residential Multi Family Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 22.6%  426 96  0.5 
Cooling Room AC 32.0% 258 83 0.5 
Cooling Air‐Source Heat Pump 1.3%  426 6  0.0 
Cooling Geothermal Heat Pump 0.0% 376 0 0.0 
Cooling Evaporative AC 1.9%  320 6  0.0 
Space Heating Electric Room Heat 58.5% 2,937 1,718 9.4 
Space Heating  Electric Furnace 16.4%  3,143 515  2.8 
Space Heating Air‐Source Heat Pump 1.3% 1,831 24 0.1 
Space Heating  Geothermal Heat Pump 0.0%  807 0  0.0 
Space Heating Secondary Heating 30.0% 443 133 0.7 
Water Heating  Water Heater <= 55 Gal 60.4%  2,100  1,269  7.0 
Water Heating Water Heater > 55 Gal 4.6% 2,220 101 0.6 
Interior Lighting  General Service Screw‐in  100.0%  405  405  2.2 
Interior Lighting Linear Lighting 100.0% 33 33 0.2 
Interior Lighting  Exempted Screw‐In 100.0% 33 33  0.2 
Exterior Lighting Screw‐in 100.0% 130 130 0.7 
Appliances Clothes Washer 59.6% 78 47  0.3 
Appliances Clothes Dryer 42.3% 785 332 1.8 
Appliances Dishwasher 73.1%  379 277  1.5 
Appliances Refrigerator 90.4% 691 624 3.4 
Appliances Freezer 23.1%  548 127  0.7 
Appliances Second Refrigerator 3.9% 660 25 0.1 
Appliances Stove/Oven 69.2%  317 219  1.2 
Appliances Microwave 86.5% 126 109 0.6 
Electronics Personal Computers 46.3%  163 75  0.4 
Electronics Monitor 94.9% 62 59 0.3 
Electronics Laptops 74.1% 43 32  0.2 
Electronics TVs 140.7% 115 162 0.9 
Electronics Printer/Fax/Copier 51.9% 43 22  0.1 
Electronics Set‐top Boxes/DVRs 64.8% 100 65 0.4 
Electronics Devices and Gadgets 100.0%  108 108  0.6 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 0.0%  3,500 0  0.0 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  950 0  0.0 
Miscellaneous Furnace Fan 33.3% 196 65 0.4 
Miscellaneous  Well pump 0.0%  556 0  0.0 
Miscellaneous Miscellaneous 100.0% 783 783 4.3 
 Total       7,681  42.2 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 914 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐20 Applied Energy Group • www.appliedenergygroup.com
Table A-19 Idaho Residential Mobile Home Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 22.5%  890 201  1.0 
Cooling Room AC 12.9% 472 61 0.3 
Cooling Air‐Source Heat Pump 26.1%  890 232  1.2 
Cooling Geothermal Heat Pump 0.0% 783 0 0.0 
Cooling Evaporative AC 0.0%  443 0  0.0 
Space Heating Electric Room Heat 6.2% 7,208 447 2.3 
Space Heating  Electric Furnace 24.8%  7,715  1,915  9.7 
Space Heating Air‐Source Heat Pump 26.1% 6,752 1,763 8.9 
Space Heating  Geothermal Heat Pump 0.0%  3,094 0  0.0 
Space Heating Secondary Heating 38.5% 493 190 1.0 
Water Heating  Water Heater <= 55 Gal  75.0%  3,288  2,466  12.4 
Water Heating Water Heater > 55 Gal 0.0% 3,476 0 0.0 
Interior Lighting  General Service Screw‐in  100.0%  441  441  2.2 
Interior Lighting Linear Lighting 100.0% 62 62 0.3 
Interior Lighting  Exempted Screw‐In 100.0% 19 19  0.1 
Exterior Lighting Screw‐in 100.0% 109 109 0.5 
Appliances Clothes Washer 94.9% 82 78  0.4 
Appliances Clothes Dryer 82.1% 830 681 3.4 
Appliances Dishwasher 74.4%  384 286  1.4 
Appliances Refrigerator 84.6% 705 597 3.0 
Appliances Freezer 48.7%  567 276  1.4 
Appliances Second Refrigerator 18.2% 742 135 0.7 
Appliances Stove/Oven 82.1%  312 256  1.3 
Appliances Microwave 92.3% 126 116 0.6 
Electronics Personal Computers 46.4%  163 76  0.4 
Electronics Monitor 78.1% 62 48 0.2 
Electronics Laptops 50.0% 43 21  0.1 
Electronics TVs 110.7% 115 127 0.6 
Electronics Printer/Fax/Copier 42.9% 43 18  0.1 
Electronics Set‐top Boxes/DVRs 89.3% 100 89 0.4 
Electronics Devices and Gadgets 100.0%  108 108  0.5 
Miscellaneous Electric Vehicles 0.0% 4,324 0 0.0 
Miscellaneous  Pool Pump 1.8%  3,500 65  0.3 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.0%  950 0  0.0 
Miscellaneous Furnace Fan 71.4% 310 222 1.1 
Miscellaneous  Well pump 0.0%  451 0  0.0 
Miscellaneous Miscellaneous 100.0% 418 418 2.1 
 Total       11,522  58.1 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 915 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐21 Applied Energy Group • www.appliedenergygroup.com
Table A-20 Idaho Residential Low-Income Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/HH) (GWh) 
Cooling Central AC 23.9%  470 112  3.8 
Cooling Room AC 28.0% 270 76 2.5 
Cooling Air‐Source Heat Pump 4.7%  476 22  0.7 
Cooling Geothermal Heat Pump 0.1% 420 0 0.0 
Cooling Evaporative AC 1.6%  300 5  0.2 
Space Heating Electric Room Heat 48.4% 4,146 2,006 67.0 
Space Heating  Electric Furnace 16.3%  4,519 738  24.6 
Space Heating Air‐Source Heat Pump 4.7% 3,187 148 4.9 
Space Heating  Geothermal Heat Pump 0.1%  1,419 1  0.0 
Space Heating Secondary Heating 33.5% 377 126 4.2 
Water Heating  Water Heater <= 55 Gal  60.2%  2,345  1,411  47.1 
Water Heating Water Heater > 55 Gal 4.2% 2,479 105 3.5 
Interior Lighting  General Service Screw‐in  100.0%  441  441  14.7 
Interior Lighting Linear Lighting 100.0% 62 62 2.1 
Interior Lighting  Exempted Screw‐In 100.0% 19 19  0.6 
Exterior Lighting Screw‐in 100.0% 109 109 3.6 
Appliances Clothes Washer 66.7% 79 53  1.8 
Appliances Clothes Dryer 48.6% 784 381 12.7 
Appliances Dishwasher 73.9%  379 280  9.4 
Appliances Refrigerator 90.3% 694 627 20.9 
Appliances Freezer 30.0%  552 165  5.5 
Appliances Second Refrigerator 8.9% 685 61 2.0 
Appliances Stove/Oven 69.4%  328 228  7.6 
Appliances Microwave 87.8% 126 111 3.7 
Electronics Personal Computers 48.0%  163 78  2.6 
Electronics Monitor 96.4% 62 60 2.0 
Electronics Laptops 72.8% 43 31  1.0 
Electronics TVs 143.6% 115 165 5.5 
Electronics Printer/Fax/Copier 53.5% 43 23  0.8 
Electronics Set‐top Boxes/DVRs 71.4% 100 71 2.4 
Electronics Devices and Gadgets 100.0%  108 108  3.6 
Miscellaneous Electric Vehicles 0.0% 4,324 1 0.0 
Miscellaneous  Pool Pump 0.2%  3,500 6  0.2 
Miscellaneous Pool Heater 0.0% 3,517 0 0.0 
Miscellaneous  Hot Tub / Spa 0.1%  950 1  0.0 
Miscellaneous Furnace Fan 40.8% 242 99 3.3 
Miscellaneous  Well pump 0.0%  546 0  0.0 
Miscellaneous Miscellaneous 100.0% 364 364 12.1 
 Total       8,293  276.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 916 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐22 Applied Energy Group • www.appliedenergygroup.com
Table A-21 Idaho Commercial Large Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 13.7% 3.08 0.42  5.6 
Cooling Water‐Cooled Chiller 8.5% 3.37 0.28 3.7 
Cooling RTU 44.5% 3.22 1.43  18.9 
Cooling PTAC 2.4% 3.80 0.09 1.2 
Cooling PTHP 0.7% 3.22 0.02  0.3 
Cooling Evaporative AC 0.0% 1.29 0.00 0.0 
Cooling Air‐Source Heat Pump 14.2% 3.22 0.46  6.0 
Cooling Geothermal Heat Pump 7.6% 1.96 0.15 2.0 
Heating Electric Furnace 1.2% 5.64 0.07  0.9 
Heating Electric Room Heat 23.8% 5.37 1.28 16.8 
Heating PTHP 0.7% 4.29 0.03  0.4 
Heating Air‐Source Heat Pump 14.2% 4.77 0.68 8.9 
Heating Geothermal Heat Pump 7.6% 3.85 0.29  3.9 
Ventilation Ventilation 100.0% 3.11 3.11 40.9 
Water Heating  Water Heater 45.2% 1.04 0.47  6.2 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 3.3 
Interior Lighting  Exempted Lighting 100.0% 0.10 0.10  1.4 
Interior Lighting High‐Bay Lighting 100.0% 1.01 1.01 13.3 
Interior Lighting  Linear Lighting 100.0% 1.72 1.72  22.7 
Exterior Lighting General Service Lighting 100.0% 0.10 0.10 1.3 
Exterior Lighting  Area Lighting 100.0% 1.28 1.28  16.8 
Exterior Lighting Linear Lighting 100.0% 0.18 0.18 2.4 
Refrigeration  Walk‐in Refrigerator/Freezer 2.0% 0.14 0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 14.0% 0.03 0.00 0.1 
Refrigeration  Glass Door Display 77.4% 0.03 0.03  0.3 
Refrigeration  Open Display Case 77.4% 0.19 0.15 2.0 
Refrigeration  Icemaker 44.9% 0.05 0.02  0.3 
Refrigeration  Vending Machine 44.9% 0.05 0.02 0.3 
Food Preparation  Oven 66.0% 0.09 0.06  0.8 
Food Preparation Fryer 76.4% 0.13 0.10 1.3 
Food Preparation  Dishwasher 43.1% 0.18 0.08  1.0 
Food Preparation Hot Food Container 43.1% 0.02 0.01 0.1 
Food Preparation  Steamer 43.1% 0.13 0.06  0.7 
Office Equipment Desktop Computer 100.0% 2.35 2.35 30.9 
Office Equipment  Laptop 100.0% 0.36 0.36  4.8 
Office Equipment Server 100.0% 0.23 0.23 3.0 
Office Equipment  Monitor 100.0% 0.41 0.41  5.4 
Office Equipment Printer/Copier/Fax 100.0% 0.21 0.21 2.8 
Office Equipment  POS Terminal 40.0% 0.03 0.01  0.2 
Miscellaneous Non‐HVAC Motors 89.6% 0.35 0.31 4.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.42  1.42  18.6 
Total       19.27 253.4 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 917 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐23 Applied Energy Group • www.appliedenergygroup.com
Table A-22 Idaho Commercial Small Office Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.17 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.45 0.00 0.0 
Cooling RTU 65.6% 3.61 2.37  13.0 
Cooling PTAC 2.3% 4.25 0.10 0.5 
Cooling PTHP 0.7% 3.61 0.03  0.1 
Cooling Evaporative AC 0.0% 1.44 0.00 0.0 
Cooling Air‐Source Heat Pump 14.0% 3.61 0.50  2.8 
Cooling Geothermal Heat Pump 7.5% 2.20 0.16 0.9 
Heating Electric Furnace 1.1% 6.82 0.08  0.4 
Heating Electric Room Heat 21.9% 6.49 1.42 7.8 
Heating PTHP 0.7% 5.16 0.04  0.2 
Heating Air‐Source Heat Pump 14.0% 5.73 0.80 4.4 
Heating Geothermal Heat Pump 7.5% 4.44 0.33  1.8 
Ventilation Ventilation 100.0% 1.25 1.25 6.9 
Water Heating  Water Heater 60.0% 0.94 0.56  3.1 
Interior Lighting General Service Lighting 100.0% 0.25 0.25 1.4 
Interior Lighting  Exempted Lighting 100.0% 0.13 0.13  0.7 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 8.3 
Interior Lighting  Linear Lighting 100.0% 1.54 1.54  8.5 
Exterior Lighting General Service Lighting 100.0% 0.16 0.16 0.9 
Exterior Lighting  Area Lighting 100.0% 1.58 1.58  8.7 
Exterior Lighting Linear Lighting 100.0% 0.07 0.07 0.4 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.66  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 8.8% 0.15 0.01 0.1 
Refrigeration   Glass Door Display 0.0% 0.15 0.00  0.0 
Refrigeration  Open Display Case 0.0% 0.90 0.00 0.0 
Refrigeration   Icemaker 5.1% 0.25 0.01  0.1 
Refrigeration  Vending Machine 5.1% 0.12 0.01 0.0 
Food Preparation  Oven 3.6% 0.19 0.01  0.0 
Food Preparation Fryer 3.6% 0.27 0.01 0.1 
Food Preparation  Dishwasher 3.6% 0.37 0.01  0.1 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.27 0.01  0.1 
Office Equipment Desktop Computer 100.0% 1.24 1.24 6.8 
Office Equipment  Laptop 100.0% 0.19 0.19  1.1 
Office Equipment Server 100.0% 0.36 0.36 2.0 
Office Equipment  Monitor 100.0% 0.22 0.22  1.2 
Office Equipment Printer/Copier/Fax 100.0% 0.17 0.17 0.9 
Office Equipment  POS Terminal 20.0% 0.10 0.02  0.1 
Miscellaneous Non‐HVAC Motors 22.0% 0.28 0.06 0.3 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.19  1.19  6.5 
Total       16.41 90.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 918 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐24 Applied Energy Group • www.appliedenergygroup.com
Table A-23 Idaho Commercial Retail Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 2.19 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 2.39 0.00 0.0 
Cooling RTU 67.0% 2.50 1.67  17.1 
Cooling PTAC 2.4% 2.62 0.06 0.6 
Cooling PTHP 0.8% 2.49 0.02  0.2 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 14.3% 2.49 0.36  3.6 
Cooling Geothermal Heat Pump 7.7% 1.52 0.12 1.2 
Heating Electric Furnace 0.5% 6.04 0.03  0.3 
Heating Electric Room Heat 9.6% 5.75 0.55 5.6 
Heating PTHP 0.8% 4.03 0.03  0.3 
Heating Air‐Source Heat Pump 14.3% 4.47 0.64 6.5 
Heating Geothermal Heat Pump 7.7% 3.04 0.23  2.4 
Ventilation Ventilation 100.0% 1.01 1.01 10.3 
Water Heating  Water Heater 61.8% 0.82 0.50  5.1 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 3.9 
Interior Lighting  Exempted Lighting 100.0% 0.36 0.36  3.7 
Interior Lighting High‐Bay Lighting 100.0% 1.51 1.51 15.4 
Interior Lighting  Linear Lighting 100.0% 2.28 2.28  23.3 
Exterior Lighting General Service Lighting 100.0% 0.24 0.24 2.4 
Exterior Lighting  Area Lighting 100.0% 0.84 0.84  8.6 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.8 
Refrigeration   Walk‐in Refrigerator/Freezer  0.0%  0.42  0.00  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 5.4% 0.09 0.01 0.1 
Refrigeration   Glass Door Display 5.4% 0.10 0.01  0.1 
Refrigeration  Open Display Case 5.4% 0.57 0.03 0.3 
Refrigeration   Icemaker 5.1% 0.32 0.02  0.2 
Refrigeration  Vending Machine 5.1% 0.15 0.01 0.1 
Food Preparation  Oven 3.6% 0.17 0.01  0.1 
Food Preparation Fryer 3.6% 0.25 0.01 0.1 
Food Preparation  Dishwasher 3.6% 0.35 0.01  0.1 
Food Preparation Hot Food Container 3.6% 0.05 0.00 0.0 
Food Preparation  Steamer 3.6% 0.25 0.01  0.1 
Office Equipment Desktop Computer 100.0% 0.18 0.18 1.8 
Office Equipment  Laptop 100.0% 0.03 0.03  0.3 
Office Equipment Server 82.0% 0.21 0.17 1.8 
Office Equipment  Monitor 100.0% 0.03 0.03  0.3 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.2 
Office Equipment  POS Terminal 100.0% 0.06 0.06  0.6 
Miscellaneous Non‐HVAC Motors 40.2% 0.34 0.13 1.4 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 7.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 4.0% 0.03 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  1.43  1.43  14.6 
Total       13.09 133.6 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 919 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐25 Applied Energy Group • www.appliedenergygroup.com
Table A-24 Idaho Commercial Restaurant Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 3.49 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 3.52 0.00 0.0 
Cooling RTU 72.9% 3.99 2.91  3.6 
Cooling PTAC 2.7% 4.69 0.13 0.2 
Cooling PTHP 1.9% 3.98 0.08  0.1 
Cooling Evaporative AC 3.3% 1.59 0.05 0.1 
Cooling Air‐Source Heat Pump 8.2% 3.98 0.33  0.4 
Cooling Geothermal Heat Pump 0.0% 2.43 0.00 0.0 
Heating Electric Furnace 19.1% 4.81 0.92  1.1 
Heating Electric Room Heat 1.7% 4.58 0.08 0.1 
Heating PTHP 1.9% 3.01 0.06  0.1 
Heating Air‐Source Heat Pump 8.2% 3.35 0.28 0.3 
Heating Geothermal Heat Pump 0.0% 2.37 0.00  0.0 
Ventilation Ventilation 100.0% 1.98 1.98 2.4 
Water Heating  Water Heater 57.9% 7.75 4.49  5.5 
Interior Lighting General Service Lighting 100.0% 1.34 1.34 1.7 
Interior Lighting  Exempted Lighting 100.0% 0.94 0.94  1.2 
Interior Lighting High‐Bay Lighting 100.0% 2.92 2.92 3.6 
Interior Lighting  Linear Lighting 100.0% 1.87 1.87  2.3 
Exterior Lighting General Service Lighting 100.0% 0.28 0.28 0.3 
Exterior Lighting  Area Lighting 100.0% 2.14 2.14  2.6 
Exterior Lighting Linear Lighting 100.0% 0.40 0.40 0.5 
Refrigeration   Walk‐in Refrigerator/Freezer  74.0%  6.59  4.88  6.0 
Refrigeration  Reach‐in Refrigerator/Freezer 7.0% 2.96 0.21 0.3 
Refrigeration   Glass Door Display 5.2% 1.52 0.08  0.1 
Refrigeration  Open Display Case 5.2% 9.00 0.47 0.6 
Refrigeration   Icemaker 97.3% 2.49 2.42  3.0 
Refrigeration  Vending Machine 97.3% 1.17 1.14 1.4 
Food Preparation  Oven 21.0% 3.95 0.83  1.0 
Food Preparation Fryer 82.0% 5.71 4.68 5.8 
Food Preparation  Dishwasher 52.5% 3.93 2.06  2.5 
Food Preparation Hot Food Container 84.0% 0.54 0.45 0.6 
Food Preparation  Steamer 16.0% 2.88 0.46  0.6 
Office Equipment Desktop Computer 100.0% 0.29 0.29 0.4 
Office Equipment  Laptop 100.0% 0.04 0.04  0.0 
Office Equipment Server 50.0% 0.34 0.17 0.2 
Office Equipment  Monitor 100.0% 0.05 0.05  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.1 
Office Equipment  POS Terminal 100.0% 0.09 0.09  0.1 
Miscellaneous Non‐HVAC Motors 20.0% 0.54 0.11 0.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  2.15  2.15  2.7 
Total       41.80 51.6 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 920 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐26 Applied Energy Group • www.appliedenergygroup.com
Table A-25 Idaho Commercial Grocery Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.5% 3.98 0.02  0.0 
Cooling Water‐Cooled Chiller 0.3% 4.33 0.01 0.0 
Cooling RTU 71.3% 4.53 3.23  6.4 
Cooling PTAC 2.1% 5.33 0.11 0.2 
Cooling PTHP 0.6% 4.15 0.03  0.1 
Cooling Evaporative AC 1.2% 1.81 0.02 0.0 
Cooling Air‐Source Heat Pump 7.2% 4.15 0.30  0.6 
Cooling Geothermal Heat Pump 0.0% 1.41 0.00 0.0 
Heating Electric Furnace 6.4% 7.41 0.47  0.9 
Heating Electric Room Heat 1.2% 7.06 0.08 0.2 
Heating PTHP 0.6% 3.42 0.02  0.0 
Heating Air‐Source Heat Pump 7.2% 3.80 0.27 0.5 
Heating Geothermal Heat Pump 0.0% 2.65 0.00  0.0 
Ventilation Ventilation 100.0% 2.18 2.18 4.3 
Water Heating  Water Heater 62.5% 2.29 1.43  2.9 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 0.8 
Interior Lighting  Exempted Lighting 100.0% 0.30 0.30  0.6 
Interior Lighting High‐Bay Lighting 100.0% 2.02 2.02 4.0 
Interior Lighting  Linear Lighting 100.0% 5.01 5.01  10.0 
Exterior Lighting General Service Lighting 100.0% 0.36 0.36 0.7 
Exterior Lighting  Area Lighting 100.0% 1.78 1.78  3.6 
Exterior Lighting Linear Lighting 100.0% 0.38 0.38 0.8 
Refrigeration   Walk‐in Refrigerator/Freezer  16.0%  5.38  0.86  1.7 
Refrigeration  Reach‐in Refrigerator/Freezer 83.1% 0.34 0.29 0.6 
Refrigeration   Glass Door Display 94.9% 3.54 3.36  6.7 
Refrigeration  Open Display Case 94.9% 20.97 19.90 39.6 
Refrigeration   Icemaker 98.9% 0.29 0.29  0.6 
Refrigeration  Vending Machine 98.9% 0.27 0.27 0.5 
Food Preparation  Oven 11.0% 0.64 0.07  0.1 
Food Preparation Fryer 87.0% 0.92 0.80 1.6 
Food Preparation  Dishwasher 54.9% 1.27 0.70  1.4 
Food Preparation Hot Food Container 73.0% 0.17 0.13 0.3 
Food Preparation  Steamer 20.0% 0.93 0.19  0.4 
Office Equipment Desktop Computer 100.0% 0.16 0.16 0.3 
Office Equipment  Laptop 64.0% 0.02 0.02  0.0 
Office Equipment Server 100.0% 0.09 0.09 0.2 
Office Equipment  Monitor 100.0% 0.03 0.03  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.0 
Office Equipment  POS Terminal 100.0% 0.06 0.06  0.1 
Miscellaneous Non‐HVAC Motors 34.6% 0.20 0.07 0.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  1.3 
Total       46.35 92.3 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 921 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐27 Applied Energy Group • www.appliedenergygroup.com
Table A-26 Idaho Commercial Health Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 16.7% 5.60 0.93  2.1 
Cooling Water‐Cooled Chiller 66.7% 7.13 4.76 10.9 
Cooling RTU 11.0% 5.57 0.61  1.4 
Cooling PTAC 0.4% 6.56 0.03 0.1 
Cooling PTHP 0.0% 5.56 0.00  0.0 
Cooling Evaporative AC 0.0% 2.23 0.00 0.0 
Cooling Air‐Source Heat Pump 0.6% 5.56 0.03  0.1 
Cooling Geothermal Heat Pump 0.9% 3.38 0.03 0.1 
Heating Electric Furnace 3.0%  17.22 0.51  1.2 
Heating Electric Room Heat 0.1% 16.40 0.01 0.0 
Heating PTHP 0.0%  10.10 0.00  0.0 
Heating Air‐Source Heat Pump 0.6% 11.22 0.06 0.1 
Heating Geothermal Heat Pump 0.9% 7.92 0.07  0.2 
Ventilation Ventilation 100.0% 4.56 4.56 10.4 
Water Heating  Water Heater 12.6% 4.56 0.57  1.3 
Interior Lighting General Service Lighting 100.0% 0.55 0.55 1.3 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  0.5 
Interior Lighting High‐Bay Lighting 100.0% 2.59 2.59 5.9 
Interior Lighting  Linear Lighting 100.0% 4.04 4.04  9.2 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.1 
Exterior Lighting  Area Lighting 100.0% 0.66 0.66  1.5 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.2 
Refrigeration   Walk‐in Refrigerator/Freezer  33.0%  0.27  0.09  0.2 
Refrigeration  Reach‐in Refrigerator/Freezer 50.0% 0.06 0.03 0.1 
Refrigeration   Glass Door Display 90.4% 0.06 0.06  0.1 
Refrigeration  Open Display Case 90.4% 0.38 0.34 0.8 
Refrigeration   Icemaker 90.4% 0.21 0.19  0.4 
Refrigeration  Vending Machine 90.4% 0.10 0.09 0.2 
Food Preparation  Oven 69.7% 0.64 0.45  1.0 
Food Preparation Fryer 80.7% 0.93 0.75 1.7 
Food Preparation  Dishwasher 53.5% 1.28 0.68  1.6 
Food Preparation Hot Food Container 53.5% 0.17 0.09 0.2 
Food Preparation  Steamer 53.5% 0.93 0.50  1.1 
Office Equipment Desktop Computer 100.0% 0.56 0.56 1.3 
Office Equipment  Laptop 100.0% 0.03 0.03  0.1 
Office Equipment Server 100.0% 0.07 0.07 0.1 
Office Equipment  Monitor 100.0% 0.10 0.10  0.2 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.1 
Office Equipment  POS Terminal 100.0% 0.04 0.04  0.1 
Miscellaneous Non‐HVAC Motors 74.1% 0.63 0.47 1.1 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 63.0% 0.04 0.02  0.1 
Miscellaneous Clothes Dryer 58.0% 0.12 0.07 0.2 
Miscellaneous  Other Miscellaneous  100.0%  4.89  4.89  11.2 
Total       29.95 68.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 922 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐28 Applied Energy Group • www.appliedenergygroup.com
Table A-27 Idaho Commercial College Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 28.5% 4.25 1.21  3.8 
Cooling Water‐Cooled Chiller 0.0% 5.34 0.00 0.0 
Cooling RTU 46.8% 2.49 1.16  3.7 
Cooling PTAC 3.0% 2.93 0.09 0.3 
Cooling PTHP 2.1% 2.48 0.05  0.2 
Cooling Evaporative AC 0.0% 1.00 0.00 0.0 
Cooling Air‐Source Heat Pump 7.9% 2.48 0.20  0.6 
Cooling Geothermal Heat Pump 5.7% 1.51 0.09 0.3 
Heating Electric Furnace 0.0%  11.87 0.00  0.0 
Heating Electric Room Heat 8.1% 11.31 0.91 2.9 
Heating PTHP 2.1% 7.12 0.15  0.5 
Heating Air‐Source Heat Pump 7.9% 7.92 0.63 2.0 
Heating Geothermal Heat Pump 5.7% 5.95 0.34  1.1 
Ventilation Ventilation 100.0% 1.52 1.52 4.8 
Water Heating  Water Heater 55.3% 2.08 1.15  3.6 
Interior Lighting General Service Lighting 100.0% 0.09 0.09 0.3 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.1 
Interior Lighting High‐Bay Lighting 100.0% 1.42 1.42 4.5 
Interior Lighting  Linear Lighting 100.0% 2.19 2.19  6.9 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.1 
Exterior Lighting  Area Lighting 100.0% 0.29 0.29  0.9 
Exterior Lighting Linear Lighting 100.0% 0.75 0.75 2.4 
Refrigeration   Walk‐in Refrigerator/Freezer  7.7%  0.16  0.01  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 13.4% 0.07 0.01 0.0 
Refrigeration   Glass Door Display 26.6% 0.04 0.01  0.0 
Refrigeration  Open Display Case 26.6% 0.22 0.06 0.2 
Refrigeration   Icemaker 26.6% 0.12 0.03  0.1 
Refrigeration  Vending Machine 26.6% 0.06 0.02 0.0 
Food Preparation  Oven 21.0% 0.24 0.05  0.2 
Food Preparation Fryer 21.0% 0.34 0.07 0.2 
Food Preparation  Dishwasher 21.0% 0.47 0.10  0.3 
Food Preparation Hot Food Container 21.0% 0.06 0.01 0.0 
Food Preparation  Steamer 21.0% 0.35 0.07  0.2 
Office Equipment Desktop Computer 100.0% 0.47 0.47 1.5 
Office Equipment  Laptop 100.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.06 0.06 0.2 
Office Equipment  Monitor 100.0% 0.08 0.08  0.3 
Office Equipment Printer/Copier/Fax 100.0% 0.06 0.06 0.2 
Office Equipment  POS Terminal 100.0% 0.02 0.02  0.1 
Miscellaneous Non‐HVAC Motors 88.8% 0.08 0.07 0.2 
Miscellaneous  Pool Pump 90.3% 0.01 0.01  0.0 
Miscellaneous Pool Heater 36.2% 0.02 0.01 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.01 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.35  0.35  1.1 
Total       13.91 43.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 923 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐29 Applied Energy Group • www.appliedenergygroup.com
Table A-28 Idaho Commercial School Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 22.1% 1.97 0.43  3.1 
Cooling Water‐Cooled Chiller 0.0% 2.47 0.00 0.0 
Cooling RTU 36.2% 1.15 0.42  3.0 
Cooling PTAC 2.4% 1.35 0.03 0.2 
Cooling PTHP 1.6% 1.15 0.02  0.1 
Cooling Evaporative AC 0.0% 0.46 0.00 0.0 
Cooling Air‐Source Heat Pump 6.1% 1.15 0.07  0.5 
Cooling Geothermal Heat Pump 4.4% 0.70 0.03 0.2 
Heating Electric Furnace 0.0% 6.44 0.00  0.0 
Heating Electric Room Heat 4.4% 6.13 0.27 2.0 
Heating PTHP 1.6% 3.86 0.06  0.5 
Heating Air‐Source Heat Pump 6.1% 4.29 0.26 1.9 
Heating Geothermal Heat Pump 4.4% 3.23 0.14  1.0 
Ventilation Ventilation 100.0% 0.71 0.71 5.1 
Water Heating  Water Heater 50.0% 0.99 0.50  3.6 
Interior Lighting General Service Lighting 100.0% 0.16 0.16 1.2 
Interior Lighting  Exempted Lighting 100.0% 0.18 0.18  1.3 
Interior Lighting High‐Bay Lighting 100.0% 0.81 0.81 5.8 
Interior Lighting  Linear Lighting 100.0% 1.51 1.51  10.9 
Exterior Lighting General Service Lighting 100.0% 0.00 0.00 0.0 
Exterior Lighting  Area Lighting 100.0% 0.12 0.12  0.9 
Exterior Lighting Linear Lighting 100.0% 0.66 0.66 4.7 
Refrigeration   Walk‐in Refrigerator/Freezer  19.0%  0.17  0.03  0.2 
Refrigeration  Reach‐in Refrigerator/Freezer 33.0% 0.08 0.02 0.2 
Refrigeration   Glass Door Display 65.7% 0.04 0.03  0.2 
Refrigeration  Open Display Case 65.7% 0.23 0.15 1.1 
Refrigeration   Icemaker 65.7% 0.13 0.08  0.6 
Refrigeration  Vending Machine 65.7% 0.06 0.04 0.3 
Food Preparation  Oven 64.8% 0.11 0.07  0.5 
Food Preparation Fryer 58.6% 0.16 0.09 0.7 
Food Preparation  Dishwasher 52.3% 0.22 0.12  0.8 
Food Preparation Hot Food Container 52.3% 0.03 0.02 0.1 
Food Preparation  Steamer 52.3% 0.16 0.08  0.6 
Office Equipment Desktop Computer 100.0% 0.29 0.29 2.1 
Office Equipment  Laptop 100.0% 0.02 0.02  0.1 
Office Equipment Server 100.0% 0.07 0.07 0.5 
Office Equipment  Monitor 100.0% 0.05 0.05  0.4 
Office Equipment Printer/Copier/Fax 100.0% 0.03 0.03 0.2 
Office Equipment  POS Terminal 36.0% 0.01 0.00  0.0 
Miscellaneous Non‐HVAC Motors 43.7% 0.07 0.03 0.2 
Miscellaneous  Pool Pump 6.0% 0.02 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.01 0.00  0.0 
Miscellaneous Clothes Dryer 11.0% 0.02 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.33  0.33  2.4 
Total       7.96 57.3 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 924 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐30 Applied Energy Group • www.appliedenergygroup.com
Table A-29 Idaho Commercial Lodging Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 2.0% 0.49 0.01  0.0 
Cooling Water‐Cooled Chiller 7.3% 0.62 0.05 0.1 
Cooling RTU 15.8% 1.52 0.24  0.8 
Cooling PTAC 38.8% 1.79 0.70 2.2 
Cooling PTHP 13.0% 1.52 0.20  0.6 
Cooling Evaporative AC 0.5% 0.61 0.00 0.0 
Cooling Air‐Source Heat Pump 5.1% 1.52 0.08  0.2 
Cooling Geothermal Heat Pump 5.5% 1.44 0.08 0.2 
Heating Electric Furnace 1.4% 3.02 0.04  0.1 
Heating Electric Room Heat 51.1% 2.88 1.47 4.6 
Heating PTHP 13.0% 2.42 0.32  1.0 
Heating Air‐Source Heat Pump 5.1% 2.69 0.14 0.4 
Heating Geothermal Heat Pump 5.5% 1.90 0.10  0.3 
Ventilation Ventilation 100.0% 0.94 0.94 3.0 
Water Heating  Water Heater 50.0% 3.20 1.60  5.0 
Interior Lighting General Service Lighting 100.0% 0.81 0.81 2.5 
Interior Lighting  Exempted Lighting 100.0% 0.43 0.43  1.3 
Interior Lighting High‐Bay Lighting 100.0% 1.29 1.29 4.0 
Interior Lighting  Linear Lighting 100.0% 0.46 0.46  1.4 
Exterior Lighting General Service Lighting 100.0% 0.04 0.04 0.1 
Exterior Lighting  Area Lighting 100.0% 1.73 1.73  5.4 
Exterior Lighting Linear Lighting 100.0% 0.03 0.03 0.1 
Refrigeration   Walk‐in Refrigerator/Freezer  3.0%  0.39  0.01  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 19.0% 0.09 0.02 0.1 
Refrigeration   Glass Door Display 58.9% 0.09 0.05  0.2 
Refrigeration  Open Display Case 58.9% 0.54 0.32 1.0 
Refrigeration   Icemaker 58.9% 0.15 0.09  0.3 
Refrigeration  Vending Machine 58.9% 0.14 0.08 0.3 
Food Preparation  Oven 13.8% 0.26 0.04  0.1 
Food Preparation Fryer 21.0% 0.37 0.08 0.2 
Food Preparation  Dishwasher 30.0% 0.51 0.15  0.5 
Food Preparation Hot Food Container 30.0% 0.07 0.02 0.1 
Food Preparation  Steamer 30.0% 0.38 0.11  0.4 
Office Equipment Desktop Computer 100.0% 0.08 0.08 0.3 
Office Equipment  Laptop 100.0% 0.01 0.01  0.0 
Office Equipment Server 100.0% 0.05 0.05 0.2 
Office Equipment  Monitor 100.0% 0.01 0.01  0.0 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.0 
Office Equipment  POS Terminal 58.0% 0.01 0.01  0.0 
Miscellaneous Non‐HVAC Motors 91.3% 0.14 0.12 0.4 
Miscellaneous  Pool Pump 76.0% 0.01 0.01  0.0 
Miscellaneous Pool Heater 27.0% 0.02 0.00 0.0 
Miscellaneous  Clothes Washer 67.0% 0.02 0.01  0.0 
Miscellaneous Clothes Dryer 26.0% 0.07 0.02 0.1 
Miscellaneous  Other Miscellaneous  100.0%  0.63  0.63  2.0 
Total       12.69 39.8 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 925 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐31 Applied Energy Group • www.appliedenergygroup.com
Table A-30 Idaho Commercial Warehouse Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 0.0% 1.59 0.00  0.0 
Cooling Water‐Cooled Chiller 0.0% 1.68 0.00 0.0 
Cooling RTU 16.0% 1.78 0.28  2.6 
Cooling PTAC 1.1% 2.09 0.02 0.2 
Cooling PTHP 0.3% 1.78 0.01  0.0 
Cooling Evaporative AC 0.0% 0.71 0.00 0.0 
Cooling Air‐Source Heat Pump 1.7% 1.78 0.03  0.3 
Cooling Geothermal Heat Pump 0.0% 1.08 0.00 0.0 
Heating Electric Furnace 2.3% 7.84 0.18  1.6 
Heating Electric Room Heat 12.4% 7.46 0.93 8.3 
Heating PTHP 0.3% 6.19 0.02  0.2 
Heating Air‐Source Heat Pump 1.7% 6.88 0.12 1.0 
Heating Geothermal Heat Pump 0.0% 5.93 0.00  0.0 
Ventilation Ventilation 100.0% 0.26 0.26 2.3 
Water Heating  Water Heater 55.3% 0.26 0.15  1.3 
Interior Lighting General Service Lighting 100.0% 0.07 0.07 0.7 
Interior Lighting  Exempted Lighting 100.0% 0.04 0.04  0.3 
Interior Lighting High‐Bay Lighting 100.0% 1.69 1.69 15.2 
Interior Lighting  Linear Lighting 100.0% 0.28 0.28  2.5 
Exterior Lighting General Service Lighting 100.0% 0.02 0.02 0.2 
Exterior Lighting  Area Lighting 100.0% 0.38 0.38  3.4 
Exterior Lighting Linear Lighting 100.0% 0.08 0.08 0.7 
Refrigeration   Walk‐in Refrigerator/Freezer  1.1%  0.49  0.01  0.0 
Refrigeration  Reach‐in Refrigerator/Freezer 2.0% 0.11 0.00 0.0 
Refrigeration   Glass Door Display 10.1% 0.11 0.01  0.1 
Refrigeration  Open Display Case 10.1% 0.67 0.07 0.6 
Refrigeration   Icemaker 10.1% 0.19 0.02  0.2 
Refrigeration  Vending Machine 10.1% 0.09 0.01 0.1 
Food Preparation  Oven 2.3% 0.03 0.00  0.0 
Food Preparation Fryer 2.3% 0.05 0.00 0.0 
Food Preparation  Dishwasher 2.3% 0.07 0.00  0.0 
Food Preparation Hot Food Container 2.3% 0.01 0.00 0.0 
Food Preparation  Steamer 2.3% 0.05 0.00  0.0 
Office Equipment Desktop Computer 100.0% 0.09 0.09 0.8 
Office Equipment  Laptop 100.0% 0.01 0.01  0.1 
Office Equipment Server 89.0% 0.10 0.09 0.8 
Office Equipment  Monitor 100.0% 0.02 0.02  0.1 
Office Equipment Printer/Copier/Fax 100.0% 0.01 0.01 0.1 
Office Equipment  POS Terminal 77.0% 0.03 0.02  0.2 
Miscellaneous Non‐HVAC Motors 49.9% 0.12 0.06 0.6 
Miscellaneous  Pool Pump 0.0% 0.00 0.00  0.0 
Miscellaneous Pool Heater 0.0% 0.00 0.00 0.0 
Miscellaneous  Clothes Washer 0.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 0.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous  100.0%  0.43  0.43  3.9 
Total       5.40 48.5 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 926 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐32 Applied Energy Group • www.appliedenergygroup.com
Table A-31 Idaho Commercial Miscellaneous Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh/Sq.Ft.) (kWh/Sq.Ft.) (GWh) 
Cooling Air‐Cooled Chiller 9.7% 1.64 0.16  2.2 
Cooling Water‐Cooled Chiller 5.0% 1.78 0.09 1.3 
Cooling RTU 56.8% 1.86 1.06  14.9 
Cooling PTAC 5.1% 2.19 0.11 1.6 
Cooling PTHP 2.6% 1.86 0.05  0.7 
Cooling Evaporative AC 0.0% 0.74 0.00 0.0 
Cooling Air‐Source Heat Pump 5.5% 1.86 0.10  1.4 
Cooling Geothermal Heat Pump 1.0% 1.13 0.01 0.2 
Heating Electric Furnace 12.5% 4.77 0.59  8.4 
Heating Electric Room Heat 14.8% 4.55 0.67 9.5 
Heating PTHP 2.6% 3.61 0.09  1.3 
Heating Air‐Source Heat Pump 5.5% 4.01 0.22 3.1 
Heating Geothermal Heat Pump 1.0% 3.13 0.03  0.5 
Ventilation Ventilation 100.0% 0.73 0.73 10.3 
Water Heating  Water Heater 53.0% 1.39 0.74  10.4 
Interior Lighting General Service Lighting 100.0% 0.38 0.38 5.3 
Interior Lighting  Exempted Lighting 100.0% 0.23 0.23  3.2 
Interior Lighting High‐Bay Lighting 100.0% 1.56 1.56 22.0 
Interior Lighting  Linear Lighting 100.0% 1.46 1.46  20.7 
Exterior Lighting General Service Lighting 100.0% 0.09 0.09 1.3 
Exterior Lighting  Area Lighting 100.0% 0.64 0.64  9.0 
Exterior Lighting Linear Lighting 100.0% 0.06 0.06 0.8 
Refrigeration   Walk‐in Refrigerator/Freezer  10.3%  0.58  0.06  0.8 
Refrigeration  Reach‐in Refrigerator/Freezer 12.1% 0.13 0.02 0.2 
Refrigeration   Glass Door Display 3.4% 0.13 0.00  0.1 
Refrigeration  Open Display Case 3.4% 0.79 0.03 0.4 
Refrigeration   Icemaker 21.6% 0.22 0.05  0.7 
Refrigeration  Vending Machine 21.6% 0.20 0.04 0.6 
Food Preparation  Oven 58.9% 0.08 0.05  0.7 
Food Preparation Fryer 29.9% 0.12 0.04 0.5 
Food Preparation  Dishwasher 15.4% 0.17 0.03  0.4 
Food Preparation Hot Food Container 15.4% 0.02 0.00 0.0 
Food Preparation  Steamer 15.4% 0.12 0.02  0.3 
Office Equipment Desktop Computer 100.0% 0.20 0.20 2.8 
Office Equipment  Laptop 100.0% 0.03 0.03  0.4 
Office Equipment Server 66.0% 0.12 0.08 1.1 
Office Equipment  Monitor 100.0% 0.03 0.03  0.5 
Office Equipment Printer/Copier/Fax 100.0% 0.02 0.02 0.3 
Office Equipment  POS Terminal 28.0% 0.03 0.01  0.1 
Miscellaneous Non‐HVAC Motors 59.9% 0.15 0.09 1.2 
Miscellaneous  Pool Pump 4.0% 0.01 0.00  0.0 
Miscellaneous Pool Heater 1.0% 0.01 0.00 0.0 
Miscellaneous  Clothes Washer 15.0% 0.00 0.00  0.0 
Miscellaneous Clothes Dryer 10.0% 0.00 0.00 0.0 
Miscellaneous  Other Miscellaneous 100.0% 0.57 0.57  8.0 
Total       10.43 147.4 

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 927 of 1057
Avista Conservation Potential Assessment for 2021-2040| Market Profiles  

  | A‐33 Applied Energy Group • www.appliedenergygroup.com
Table A-32 Idaho Industrial Market Profile
End Use Technology Saturation EUI Intensity Usage 
(kWh) (kWh/Employee) (GWh) 
Cooling Air‐Cooled Chiller 2.5%  14,936.14 373.40  2.0 
Cooling Water‐Cooled Chiller 2.5% 15,732.18 393.30 2.1 
Cooling RTU 11.4%  16,648.18 1,898.60  10.3 
Cooling Air‐Source Heat Pump 1.7% 16,640.58 281.39 1.5 
Cooling Geothermal Heat Pump 0.0%  11,099.27 0.00  0.0 
Heating Electric Furnace 2.3% 73,387.09 1,683.53 9.2 
Heating Electric Room Heat 12.4%  69,892.47 8,672.59  47.2 
Heating Air‐Source Heat Pump 1.7% 64,443.40 1,089.73 5.9 
Heating Geothermal Heat Pump 0.0%  42,983.75 0.00  0.0 
Ventilation Ventilation 100.0% 2,427.96 2,427.96 13.2 
Interior Lighting  General Service Lighting  100.0%  465.63  465.63  2.5 
Interior Lighting High‐Bay Lighting 100.0% 7,284.44 7,284.44 39.6 
Interior Lighting  Linear Lighting 100.0%  1,210.90 1,210.90  6.6 
Exterior Lighting General Service Lighting 100.0% 85.72 85.72 0.5 
Exterior Lighting  Area Lighting 100.0%  1,624.05 1,624.05  8.8 
Exterior Lighting Linear Lighting 100.0% 332.72 332.72 1.8 
Motors Pumps 100.0%  4,278.85 4,278.85  23.3 
Motors Fans & Blowers 100.0% 5,138.64 5,138.64 28.0 
Motors Compressed Air 100.0%  4,155.05 4,155.05  22.6 
Motors Material Handling 100.0% 8,788.33 8,788.33 47.8 
Motors Other Motors 100.0%  147.48 147.48  0.8 
Process Process Heating 100.0% 7,235.19 7,235.19 39.4 
Process Process Cooling 100.0%  1,899.62 1,899.62  10.3 
Process Process Refrigeration 100.0% 1,899.62 1,899.62 10.3 
Process Process Electrochemical 100.0%  731.25 731.25  4.0 
Process Process Other 100.0% 793.59 793.59 4.3 
Miscellaneous  Miscellaneous 100.0%  4,365.54 4,365.54  23.8 
Total       67,257.13 366.1 
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 928 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 929 of 1057

| B‐1 
Applied Energy Group • www.appliedenergygroup.com

MARKET ADOPTION (RAMP) RATES
This appendix presents the Power Council’s 7th Plan ramp rates we applied to technical potential to estimate Technical Achievable Potential.
Table B-1 Measure Ramp Rates Used in CPA
Key 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 
LO12Med  9%  19%  28%  37%  47%  55%  62%  67%  71%  75%  78%  80%  82%  83% 84%  85%  85%  85%  85%  85% 
LO5Med 4% 8% 13% 20% 27% 35% 45% 54% 63% 71% 76% 81% 83% 84% 85% 85% 85% 85% 85% 85% 
LO1Slow  0%  1%  1%  3%  5%  7%  11%  16%  22%  29%  37%  46%  54%  62%  69%  75%  79%  82%  84%  85% 
LO50Fast 38% 56% 68% 76% 81% 83% 84% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 85% 
LO20Fast  19%  32%  42%  49%  55%  61%  65%  69%  72%  75%  78%  79%  81%  82%  83%  84%  84%  84%  85%  85% 
LOEven20 4% 9% 13% 17% 21% 26% 30% 34% 38% 43% 47% 51% 55% 60% 64% 68% 72% 77% 81% 85% 
LOMax60  1%  3%  5%  8%  12%  16%  20%  24%  28%  31%  34%  37%  40%  42%  45%  47%  49%  51%  53%  55% 
LO3Slow 0% 1% 3% 5% 9% 15% 22% 31% 40% 49% 57% 65% 71% 75% 79% 81% 83% 84% 85% 85% 
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% 7% 8% 10% 11% 11% 10% 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%  3%  2%  1% 
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%  0%  0%  0% 
RetroEven20 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 
RetroMax60  1%  2%  3%  4%  5%  5%  5%  4%  4%  4%  4%  3%  3%  3%  3%  3%  3%  2%  2%  2% 
Retro3Slow 1% 1% 2% 3% 5% 7% 8% 10% 11% 11% 10% 9% 7% 6% 4% 3% 2% 1% 1% 0% 

* Assumption of 55% maximum achievability from Council’s 7th Power Plan

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 930 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 931 of 1057

  | C‐1 Applied Energy Group • www.appliedenergygroup.com

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. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 932 of 1057
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 933 of 1057

  | D‐1 Applied Energy Group • www.appliedenergygroup.com

HB 1444 IMPACT ANALYSIS
In April 2019, the Washington State Legislature passed HB 1444, which established new energy efficiency
requirements for some consumer technologies sold in Washington, particularly water-using equipment,
commercial kitchen equipment, and desktop computing equipment. These devices have associated
savings potential within the CPA which would be affected by this legislation, in that the savings would
become part of the baseline, or “naturally occurring” efficiency.
AEG did not reconfigure and rerun the CPA to include the impacts of this legislation, as the standards
were not yet in place at the time the study was designed and developed, however, an estimate of the likely
impacts is provided in Table D-1 below. AEG estimates that 5% - 7% of Avista’s Washington Technical
Achievable Potential for the biennium period could be moved into the baseline by HB 1444.
Table D-1 Impacts of HB 1444 on EE Potential13
Technical Achievable Potential MWh ‐ CPA Total 2022 2030 2040 
Idaho 50,201  328,073  673,115 
Washington 99,977 636,490 1,271,968 
Total 150,178  964,564  1,945,083 

HB 1444 Affected Measures ‐ TAP MWh 2022 2030 2040 
Residential         
Monitor 1,537 7,994 8,552 
Personal Computers 634  2,846  2,913 
Water Heater ‐ Faucet Aerators 19 693 821 
Water Heater ‐ Low‐Flow Showerheads 2,834  10,144  7,814 
Commercial       
Desktop Computer 418  2,285  2,600 
Dishwasher 24 756 2,461 
ENERGY STAR Water Cooler 80  433  879 
Fryer 40 1,256 2,937 
Hot Food Container 18  537  2,005 
Monitor 67 300 319 
Steamer 44  2,010  8,070 
Water Heater ‐ Faucet Aerators/Low Flow Nozzles 442 990 1,044 
Water Heater ‐ Low‐Flow Showerheads 242  536  562 
Total 6,400  30,779  40,977 
% of WA 6.4%  4.8%  3.2% 
% of Total 4.3%  3.2%  2.1% 

13 Note: HB 1444 also requires direct load control switches to be present on storage water heaters, which would affect the cost of the
Residential Water Heating DLC program described in Chapter 6, but AEG did not assume a change in participation or potential as a result
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 934 of 1057
Avista Conservation Potential Assessment for 2021-2040 

Applied Energy Group, Inc. 500 Ygnacio Valley Rd, Suite 250 Walnut Creek, CA 94596 P: 510.982.3525
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 935 of 1057

2020 Electric Integrated
Resource Plan

Appendix E – Conservation
Potential Assessment Measure
Assumptions

Please see attached spreadsheet

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 936 of 1057
2020 Electric Integrated
Resource Plan
Appendix F – Resource
Adequacy in the Pacific
Northwest by E3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 937 of 1057

Resource Adequacy in the
Pacific Northwest

March 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 938 of 1057

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 939 of 1057

© 2019 Copyright. All Rights Reserved.
Energy and Environmental Economics, Inc.
44 Montgomery Street, Suite 1500
San Francisco, CA 94104
415.391.5100
www.ethree.com

Project Team:
Zach Ming
Arne Olson
Huai Jiang
Manohar Mogadali
Nick Schlag

Resource Adequacy in the
Pacific Northwest

March 2019
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 940 of 1057

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 941 of 1057
Table of Contents
Executive Summary ................................................................................................... i
Background and Approach .......................................................................................... ii
Key Findings ................................................................................................................... ii
1 Introduction ......................................................................................................... 1
1.1 Study Background & Context ........................................................................... 1
1.2 Prior Studies ........................................................................................................ 2
1.3 Purpose of Study ................................................................................................ 2
1.4 Report Contents .................................................................................................. 3
2 Resource Adequacy in the Northwest ............................................................ 4
2.1 What is Resource Adequacy? .......................................................................... 4
2.2 Planning Practices in the Northwest ............................................................... 6
3 Modeling Approach ........................................................................................... 9
3.1 Renewable Energy Capacity Planning (RECAP) Model ............................. 9
3.2 Study Region ..................................................................................................... 14
3.3 Scenarios & Sensitivities ................................................................................. 16
3.4 Key Portfolio Metrics ........................................................................................ 18
3.5 Study Caveats ................................................................................................... 20
4 Key Inputs & Assumptions .............................................................................. 22
4.1 Load Forecast ................................................................................................... 22
4.2 Existing Resources........................................................................................... 24
4.3 Candidate Resources ...................................................................................... 31
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 942 of 1057
4.4 Estimating Cost and GHG Metrics ................................................................ 35
5 Results ................................................................................................................ 36
5.1 Short-Term Outlook (2018) ............................................................................. 36
5.2 Medium-Term Outlook (2030) ........................................................................ 38
5.3 Long-Term Outlook (2050) ............................................................................. 41
6 Discussion & Implications ............................................................................... 67
6.1 Land Use Implications of High Renewable Scenarios .............................. 67
6.2 Reliability Standards ........................................................................................ 68
6.3 Benefits of Reserve Sharing ........................................................................... 71
7 Conclusions ....................................................................................................... 74
7.1 Key Findings ...................................................................................................... 75
Appendix A. Assumption Development Documentation ........................ A-1
Appendix B. RECAP Model Documentation ............................................. B-1
Appendix C. Renewable Profile Development .......................................... C-8

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 943 of 1057
Study Sponsors
This study was sponsored by Puget Sound Energy, Avista, NorthWestern Energy, and the Public Generating
Pool (PGP). PGP is a trade association representing 10 consumer-owned utilities in Oregon and Washington:
Chelan County PUD, Clark Public Utilities, Cowlitz County PUD, Eugene Water and Electric Board, Klickitat
PUD, Grant County PUD, Lewis County PUD, Tacoma Power, Snohomish County PUD, and Benton PUD.
Acknowledgements
E3 thanks the staff of the Northwest Power and Conservation Council (NWPCC) for providing data and
technical review.
Conventions
The following conventions are used throughout this report:
 All costs are reported in 2016 dollars.
 All levelized costs are assumed to be levelized in real terms (i.e., a stream of payments over the
lifetime of the contract that is constant in real dollars).

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 944 of 1057
Acronyms
CONE Cost of New Entry
DR Demand Response
EE Energy Efficiency
ELCC Effective Load Carrying Capability
EUE Expected Unserved Energy
FOR Forced Outage Rate
GENESYS NWPCC’s Generation Evaluation System Model
GHG Greenhouse Gas
ISO Independent System Operator
LOLE Loss-of-Load Expectation
LOLF Loss-of-Load Frequency
LOLP Loss-of-Load Probability
MISO Midwest Independent System Operator
MMT Million Metric Ton
MTTR Mean Time to Repair
NERC North American Electric Reliability Corporation
NREL National Renewable Energy Laboratory
NWPCC Northwest Power and Conservation Council
NWPP Northwest Power Pool
PNUCC Pacific Northwest Utilities Conference Committee
PRM Planning Reserve Margin
RA Resource Adequacy
RECAP E3’s Renewable Energy Capacity Planning Model
RPS Renewables Portfolio Standard
RTO Regional Transmission Operator
SPP Southwest Power Pool
WECC Western Electricity Coordinating Council
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 945 of 1057
Executive Summary
The Pacific Northwest is expected to undergo significant changes to its electricity generation resource mix
over the next 30 years due to changing economics of resources and more stringent environmental policy
goals. In particular, the costs of wind, solar, and battery storage have experienced significant declines in
recent years, a trend that is expected to continue. Greenhouse gas and other environmental policy goals
combined with changing economics have put pressure on existing coal resources, and many coal power
plants have announced plans to retire within the next decade.
As utilities become more reliant on intermittent renewable energy resources (wind and solar) and energy-
limited resources (hydro and battery storage) and less reliant on dispatchable firm resources (coal),
questions arise about how the region will serve future load reliably. In particular, policymakers across the
region are considering many different policies – such as carbon taxes, carbon caps, renewable portfolio
standards, limitations on new fossil fuel infrastructure, and others – to reduce greenhouse gas emissions
in the electricity sector and across the broader economy. The environmental, cost, and reliability
implications of these various policy proposals will inform electricity sector planning and policymaking in
the Pacific Northwest.
This study finds that deep decarbonization of the Northwest grid is feasible without sacrificing reliable
electric load service. But this study also finds that, absent technological breakthroughs, achieving 100%
GHG reductions using only wind, solar, hydro, and energy storage is both impractical and prohibitively
expensive. Firm capacity – capacity that can be relied upon to produce energy when it is needed the most,
even during the most adverse weather conditions – is an important component of a deeply-decarbonized
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 946 of 1057
grid. Increased regional coordination is also a key to ensuring reliable electric service at reasonable cost
under deep decarbonization.
Background and Approach
This study builds on the previous Northwest Low-Carbon Scenario Analysis conducted by E3 for PGP in
2017-2018 by focusing on long-run reliability and Resource Adequacy. This study uses E3’s Renewable
Energy Capacity Planning (RECAP) model, a loss-of-load-probability model designed specifically to test the
Resource Adequacy of high-renewable electricity systems under a wide variety of weather conditions,
renewable generation, and forced outages of electric generating resources. Specifically, this study
examines four key questions:
 How to maintain Resource Adequacy in the 2020-2030 timeframe under growing loads and
increasing coal retirements?
 How to maintain Resource Adequacy in the 2050 timeframe under different levels of carbon
abatement goals, including zero carbon?
 How much effective capacity can be provided by wind, solar, electric energy storage, and demand
response?
 How much firm capacity is needed to maintain reliable electric service at various levels of carbon
reductions?
Key Findings
1. It is possible to maintain Resource Adequacy for a deeply decarbonized Northwest electricity grid,
as long as sufficient firm capacity is available during periods of low wind, solar, and hydro
production;
o Natural gas generation is the most economic source of firm capacity today;
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o Adding new gas generation capacity is not inconsistent with deep reductions in carbon
emissions because the significant quantities of zero-marginal-cost renewables will ensure
that gas is only used during reliability events;
o Wind, solar, demand response, and short-duration energy storage can contribute but
have important limitations in their ability to meet Northwest Resource Adequacy needs;
o Other potential low-carbon firm capacity solutions include (1) new nuclear generation,
(2) fossil generation with carbon capture and sequestration, (3) ultra-long duration
electricity storage, and (4) replacing conventional natural gas with carbon-neutral gas
such as hydrogen or biogas.
2. It would be extremely costly and impractical to replace all carbon-emitting firm generation
capacity with solar, wind, and storage, due to the very large quantities of these resources that
would be required;
o Firm capacity is needed to meet the new paradigm of reliability planning under deep
decarbonization, in which the electricity system must be designed to withstand prolonged
periods of low renewable production once storage has depleted; renewable overbuild is
the most economic solution to completely replace carbon-emitting resources but requires
a 2x buildout that results in curtailment of almost half of all wind and solar production.
3. The Northwest is expected to need new capacity in the near term in order to maintain an
acceptable level of Resource Adequacy after planned coal retirements.
4. Current planning practices risk underinvestment in the new capacity needed to ensure Resource
Adequacy at acceptable levels;
o Reliance on market purchases or front-office transactions (FOTs) reduces the cost of
meeting Resource Adequacy needs on a regional basis by taking advantage of load and
resource diversity among utilities in the region;
o Capacity resources are not firm without a firm fuel supply; investment in fuel delivery
infrastructure may be required to ensure Resource Adequacy even under a deep
decarbonization trajectory;
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o Because the region lacks a formal mechanism for ensuring adequate physical firm
capacity, there is a risk that reliance on market transactions may result in double-counting
of available surplus generation capacity;
o The region might benefit from and should investigate a formal mechanism to share
planning reserves on a regional basis, which may help ensure sufficient physical firm
capacity and reduce the quantity of capacity required to maintain Resource Adequacy.

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1 Introduction
1.1 Study Background & Context
The Pacific Northwest is expected to undergo significant changes to its electricity generation resource mix
over the next 30 years due to changing economics of resources and more stringent environmental policy
goals. In particular, the costs of wind, solar, and battery storage have experienced significant declines in
recent years, a trend that is expected to continue. Greenhouse gas and other environmental policy goals
combined with changing economics have put pressure on existing coal resources, and many coal power
plants have announced plans to retire within the next decade.
As utilities become more reliant on intermittent renewable energy resources (wind and solar) and energy-
limited resources (hydro and battery storage) and less reliant on dispatchable firm resources (coal),
questions arise about how the region will serve future load reliably. In particular, policymakers across the
region are considering many different policies – such as carbon taxes, carbon caps, renewable portfolio
standards, limitations on new fossil fuel infrastructure, and others – to reduce greenhouse gas emissions
in the electricity sector and across the broader economy. The environmental, cost, and reliability
implications of these various policy proposals will inform electricity sector planning and policymaking in
the Pacific Northwest.
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1.2 Prior Studies
In 2017-2018, E3 completed a series of studies1 for PGP and Climate Solutions to evaluate the costs of
alternative electricity decarbonization strategies in Washington and Oregon. These studies were
conducted using E3’s RESOLVE model, which is a dispatch and investment model that identifies optimal
long-term generation and transmission investments in the electric system to meet various
decarbonization and renewable energy targets. The studies found that the least-cost pathway to reduce
greenhouse gases from electricity generation is to replace coal generation with a mix of energy efficiency,
renewables, and natural gas generation. While these studies examined in great detail the economics of
new resources needed to achieve decarbonization, including the type, quantity, and location of these
resources, they did not look in-depth at reliability and Resource Adequacy.
1.3 Purpose of Study
This study builds on the previous Northwest Low-Carbon Scenario Analysis conducted by E3 for PGP in
2017-2018 by focusing on long-run reliability and Resource Adequacy. This study uses E3’s Renewable
Energy Capacity Planning (RECAP) model, a loss-of-load-probability model designed specifically to test the
Resource Adequacy of high-renewable electricity systems under a wide variety of weather conditions,
renewable generation, and forced outages of electric generating resources. Specifically, this study
examines four key questions:
 How to maintain Resource Adequacy in the 2020-2030 timeframe under growing loads and
increasing coal retirements?
 How to maintain Resource Adequacy in the 2050 timeframe under different levels of carbon
abatement goals, including zero carbon?
1 https://www.ethree.com/projects/study-policies-decarbonize-electric-sector-northwest-public-generating-pool-2017-present/
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 How much effective capacity can be provided by wind, solar, electric energy storage, and demand
response?
 How much firm capacity is needed to maintain reliable electric service at various levels of carbon
reductions?
1.4 Report Contents
The remainder of this report is organized as follows:
 Section 2 introduces Resource Adequacy and current practices in the Northwest
 Section 3 describes the study’s modeling approach
 Section 4 highlights key inputs and assumptions used in the modeling
 Section 5 presents results across a variety of time horizons and resource portfolios
 Section 6 discusses implications of the results
 Section 7 summarizes the study’s conclusions and lessons learned

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2 Resource Adequacy in the Northwest
2.1 What is Resource Adequacy?
Resource adequacy is the ability of an electric power system to serve load across a broad range of weather
and system operating conditions, subject to a long-run standard on the maximum frequency of reliability
events where generation is insufficient to serve all load. The resource adequacy of a system thus depends
on the characteristics of its load—seasonal patterns, weather sensitivity, hourly patterns—as well as its
resources—size, dispatchability, outage rates, and other limitations on availability. Ensuring resource
adequacy is an important goal for utilities seeking to provide reliable service to their customers.
While utility portfolios are typically designed to meet specified resource adequacy targets, there is no
single mandatory or voluntary national standard for resource adequacy. Across North America, resource
adequacy standards are established by utilities, regulatory commissions, and regional transmission
operators, and each uses its own conventions to do so. The North American Electric Reliability Council
(NERC) and the Western Electric Coordinating Council (WECC) publish information about resource
adequacy but have no formal governing role.
While a variety of approaches are used, the industry best practice is to establish a standard for resource
adequacy using a two-step process:
 Loss-of-load-probability (LOLP) modeling: LOLP modeling uses statistical techniques and/or
Monte Carlo approaches to simulate the capability of a generation portfolio to produce sufficient
generation to meet loads across a wide range of different conditions. Utilities plan the system to
meet a specific reliability standard that is measured through LOLP modeling such as the expected
frequency and/or size of reliability events; a relatively common standard used in LOLP modeling
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is “one day in ten years,” which is often translated to an expectation of 24 hours of lost load every
ten years, or 2.4 hours per year.2
 Planning reserve margin (PRM) requirements: Utilities then determine the required PRM
necessary to ensure that the system will meet the specific the reliability standard from the LOLP
modeling. A PRM establishes a total requirement for capacity based on the peak demand of an
electric system plus some reserve margin to account for unexpected outages and extreme
conditions; reserve margin requirements typically vary among utilities between 12-19% above
peak demand. To meet this need, capacity from resources that can produce their full power on
demand (e.g., nuclear, gas, coal) are typically counted at or near 100%, whereas resources that
are constrained in their availability or ability to dispatch (e.g., hydro, storage, wind, solar) are
typically de-rated below full capacity.
While LOLP modeling is more technically rigorous, most utilities perform LOLP modeling relatively
infrequently and use a PRM requirement to heuristically ensure compliance with a specific reliability
standard due to its relative simplicity and ease of implementation. The concept and application of a PRM
to measure resource adequacy has historically worked well in a paradigm in which most generation
capacity is “firm”; that is, the resource will be available to dispatch to full capacity, except in the event of
unexpected forced outages. Under this paradigm, as long as the system has sufficient capacity to meet its
peak demand (plus some reserve margin for extreme weather and unexpected forced outages), it will be
capable of serving load throughout the rest of the year as well.
However, growing penetrations of variable (e.g., wind and solar) and energy-limited (e.g., hydro, electric
energy storage, and demand response) resources require the application of increasingly sophisticated
modeling tools to determine the appropriate PRM and to measure the contribution of each resource
towards resource adequacy. Because wind and solar do not always generate during the system peak and
because storage may run out of charge while it is serving the system peak, these resources are often de-
2 Other common interpretations of the “one day in ten year” standard include 1 “event” (of unspecified duration) in ten years or “one hour in ten
years” i.e., 0.1 hrs/yr
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rated below the capability of a fully dispatchable thermal generator when counted toward meeting the
PRM.
2.2 Planning Practices in the Northwest
A number of entities within the Northwest conduct analysis and planning for resource adequacy within
the region. Under its charter to ensure prudent management of the region’s federal hydro system while
balancing environmental and energy needs, the Northwest Power and Conservation Council (NWPCC)
conducts regular assessments of the resource adequacy position for the portion of the Northwest region
served by the Bonneville Power Administration. The NWPCC has established an informal reliability target
for the region of 5% annual loss of load probability3—a metric that ensures that the region will experience
reliability events in fewer than one in twenty years—and uses GENESYS, a stochastic LOLP model with a
robust treatment of the resource’s variable hydroelectric conditions and capabilities, to examine whether
regional resources are sufficient to meet this target on a five-year ahead basis.4 These studies provide
valuable information referenced by regulators and utilities throughout the region.
While the work of the Council is widely regarded as the most complete regional assessment of resource
adequacy for the smaller region, the Council itself holds no formal decision-making authority to prescribe
new capacity procurement or to enforce its reliability standards. Instead, the ultimate administration of
resource adequacy lies in the hands of individual utilities, often subject to the oversight of state
commissions. Most resource adequacy planning occurs within the planning and procurement processes
3 This Council’s standard, which focuses only on whether a reliability event occurred within a year, is unique to the Northwest and is not widely used
throughout the rest of the North America
4 The most recent of these reports, the Pacific Northwest Power Supply Adequacy Assessment for 2023, is available at:
https://www.nwcouncil.org/sites/default/files/2018-7.pdf (accessed January 18, 2019).
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of utilities: individual utilities submit integrated resource plans (IRPs) that consider long-term resource
adequacy needs and conduct resource solicitations to satisfy those needs.
Utilities rely on a combination of self-owned generation, bilateral contracts, and front-office transactions
(FOTs) to satisfy their resource adequacy requirements. FOTs represent short-term firm market purchases
for physical power delivery. FOTs are contracted on both a month-ahead, day-ahead and hour-ahead
basis. A survey of the utility IRPs in the Northwest reveals that most of the utilities expect to meet a
significant portion of their peak capacity requirements in using FOTs.
FOTs may be available to utilities for several potential reasons including 1) the region as a whole has a
capacity surplus and some generators are uncontracted to a specific utility or 2) natural load diversity
between utilities such that one utility may have excess generation during another’s peak load conditions
and vice versa. The use of FOTs in place of designated firm resources can result in lower costs of providing
electric service, as the cost of contracting with existing resources is generally lower than the cost of
constructing new resources.
However, as loads grow in the region and coal generation retires, the region’s capacity surplus is shrinking,
and questions are emerging about whether sufficient resources will be available for utilities to contract
with for month-ahead and day-ahead capacity products. In a market with tight load-resource balance,
extensive reliance on FOTs risks under-investment in the firm capacity resources needed for reliable load
service.

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Table 1: Contribution of FOTs Toward Peak Capacity Requirements in 2018 in the Northwest
Utility Capacity
Requirement (MW)
Front Office
Transactions (MW)
% of Capacity
Requirement from FOTs
Puget Sound5 6,100

1,800 30%
Avista6 2,150

- 0%
Idaho Power7 3,078

313 10%
PacifiCorp8 11,645

462 4%
BPA9 11,506

- 0%
PGE10 4,209

106 3%
NorthWestern11 1,205

503 42%

5 Figure 6-7: Available Mid C Tx plus Additional Mid-C Tx w/ renewals in PSE 2017 IRP: https://www.pse.com/-/media/PDFs/001-Energy-Supply/001-
Resource-Planning/8a_2017_PSE_IRP_Chapter_book_compressed_110717.pdf?la=en&revision=bb9e004c-9da0-4f75-a594-
6c30dd6223f4&hash=75800198E4E8517954C63B3D01E498F2C5AC10C2
6 Figure 6.1 (for peak load), Chapter 4 Tables for resources in Avista 2017 IRP: https://www.myavista.com/-/media/myavista/content-
documents/about-us/our-company/irp-documents/2017-electric-irp-final.pdf?la=en
7 Table 9.11 in Idaho Power 2017 IRP: https://docs.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/IRP.pdf
8 Table 5.2 in PacifiCorp 2017 IRP (Interruptible Contracts + Purchases):
https://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2017_IRP/2017_IRP_VolumeI_IRP_Final.pdf
9 Bottom of the page in BPA fact sheet: https://www.bpa.gov/news/pubs/GeneralPublications/gi-BPA-Facts.pdf
10 PGE 2016 IRP Table P-1 Spot Market Purchases (rounded from 106), Capacity Need : https://www.portlandgeneral.com/our-company/energy-
strategy/resource-planning/integrated-resource-planning/2016-irp
11 Table 2-2 for peak load and netted out existing resources (Ch. 8) @ 12%PRM from NorthWestern Energy 2015 IRP:
https://www.northwesternenergy.com/our-company/regulatory-environment/2015-electricity-supply-resource-procurement-plan
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3 Modeling Approach
3.1 Renewable Energy Capacity Planning (RECAP) Model
3.1.1 MODEL OVERVIEW
This study assesses the resource adequacy of electric generating resource portfolios for different
decarbonization scenarios in the Northwest region using E3’s Renewable Energy Capacity Planning
(RECAP) model. RECAP is a loss-of-load-probability model developed by E3 that has been used extensively
to test the resource adequacy of electric systems across the North American continent, including
California, Hawaii, Canada, the Pacific Northwest, the Upper Midwest, Texas, and Florida.
RECAP calculates a number of reliability metrics which are used to assess the resource adequacy for an
electricity system with a given set of loads and generating resources.
 Loss of Load Expectation (hrs/yr) – LOLE
o The total number of hours in a year where load + reserves exceeds generation
 Expected Unserved Energy (MWh/yr) – EUE
o The total quantity of unserved energy in a year when load + reserves exceeds generation
 Loss of Load Probability (%/yr) – LOLP
o The probability in a year that load + reserves exceeds generation at any time
 Effective Load Carrying Capability (%) – ELCC
o The additional load met by an incremental generator while maintaining the same level of
system reliability (used for dispatch-limited resources such as wind, solar, storage, hydro,
and demand response). Equivalently, this is the quantity of perfectly dispatchable
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generation that could be removed from the system by an incremental dispatch-limited
generator
 Planning Reserve Margin (%) – PRM
o The resource margin above a 1-in-2 peak load, in %, that is required in order to meet a
specific reliability standard (such as 2.4 hrs./yr. LOLE)
This study uses 2.4 hrs./yr. LOLE reliability standard which is based on a commonly accepted 1-day-in-10-
year standard. All portfolios that are developed by RECAP in this analysis for resource adequacy are
designed to meet a 2.4 hrs./yr. LOLE standard.
RECAP calculates reliability statistics by simulating the electric system with a specific set of generating
resources and loads under a wide variety of weather years, renewable generation years, and stochastic
forced outages of electric generation resources and imports on transmission. By simulating the system
thousands of times with different combinations of these factors, RECAP provides robust, stochastic
estimation of LOLE and other reliability statistics.
RECAP was specifically designed to calculate the reliability of electric systems operating under high
penetrations of renewable energy and storage. Correlations enforced within the model capture linkage
among load, weather, and renewable generation conditions. Time-sequential simulation tracks the state
of charge and energy availability for dispatch-limited resources such as hydro, energy storage, and
demand response.
3.1.2 MODEL METHODOLOGY
The steps of the RECAP modeling process are shown below in Figure 1. RECAP calculates long-run resource
availability through Monte Carlo simulation of electricity system resource availability using weather
conditions from 1948-2017. Each simulation begins on January 1, 1948 and runs hourly through December
31, 2017. Hourly electric loads for 1948-2017 are synthesized using statistical analysis of actual load
shapes and weather conditions for 2014-2017 combined with recorded historical weather conditions.
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Then, hourly wind and solar generation profiles are drawn from simulations created by the National
Renewable Energy Laboratory (NREL) and paired with historical weather days through an E3-created day-
matching algorithm. Next, nameplate capacity and forced outage rates (FOR) for thermal generation are
drawn from various sources including the GENESYS database and the Western Electric Coordinating
Council’s Anchor Data Set. Hydro is dispatched based on the load net of renewable and thermal
generation. Annual hydro generation values are drawn randomly from 1929-2008 water years and shaped
to calendar months and weeks based on the Northwest Power and Conservation Council’s GENESYS
model. For each hydro year, we identify all the hydro dispatch constraints including maximum and
minimum power capacity, 2-hour to 10-hour sustained peaking limits, and hydro budget, specific to the
randomly-drawn hydro condition. For each x-hour sustained peaking limit (where x = 2, 4, and 10), RECAP
dispatches hydro so that the average capacity over consecutive x hours does not exceed the sustained
peaking capability. Overall, hydro is dispatched to minimize the post-hydro net load subject to the above
constraints. In other words, hydro is used within assumed constraints to meet peak load needs while
minimizing loss-of-load. Finally, RECAP uses storage and demand response to tackle the loss-of-load hours
and storage is only discharged during loss-of-load hours. A more detailed description of the RECAP model
is in Appendix B.2.
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Figure 1: Overview of RECAP Model

3.1.3 PORTFOLIO DEVELOPMENT
RECAP is used in this study to both test the reliability of the existing 2018 Greater Northwest electricity
system as well as to determine a total capacity need in 2030 and to develop portfolios in 2050 under
various levels of decarbonization that meet a 1-day-in-10-year reliability standard of 2.4 hrs./yr.
To develop each 2050 decarbonization portfolio, RECAP calculates the reliability of the system in 2050
after forecasted load growth and the removal of all fossil generation but the maintenance of all existing
carbon-free resources. Unsurprisingly, these portfolios are significantly less reliable than the required 2.4
hrs./yr. nor do they deliver enough carbon-free generation to meet the various decarbonization targets.
To improve the reliability and increase GHG-free generation of these portfolios, RECAP tests the
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contribution of small, equal-cost increments of candidate GHG-free resources. The seven candidate
resources in this study are:
 Northwest Wind (WA/OR)
 Montana Wind
 Wyoming Wind
 Solar (based on an assumed diverse mix of resources from each state)
 4-Hour Storage
 8-Hour Storage
 16-Hour Storage
The resource that improves reliability the most (as measured in loss-of-load-expectation) is then added
to the system. This process is repeated until the delivered GHG-free generation is sufficient to meet the
GHG target (e.g., 80% reduction) for each particular scenario. Once a portfolio has achieved the objective
GHG target, RECAP calculates the residual quantity of perfect firm capacity that is needed to bring the
portfolio in compliance with a reliability standard of 2.4 hrs./yr. This perfect firm MW capacity is converted
to MW of natural gas capacity by grossing up by 5% to account for forced outages. Natural gas capacity is
used because it is the most economic source of firm capacity. To the extent that other carbon-free
resources can substitute for natural gas capacity, this is reflected in deeper decarbonization portfolios
that have higher quantities of wind, solar, and storage along with a smaller residual requirement for firm
natural gas capacity.
Figure 2 illustrates a simple example of this portfolio development process where RECAP has 3 candidate
resources: wind, solar, and storage. The model evaluates the contribution to reliability of equal-cost
increments of the three candidate resources and selects the resource that improves reliability the most.
From that new portfolio, the process is repeated until either the system reaches a reliability standard of
2.4 or a particular GHG target is achieved.
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Figure 2: RECAP Portfolio Development Process

3.2 Study Region
The geographic region for this study consists of the U.S. portion of the Northwest Power Pool (NWPP),
excluding Nevada, which this study refers to as the “Greater Northwest”. This region includes the states
of Washington, Oregon, Idaho, Utah, and parts of Montana and Wyoming.
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Figure 3: The study region - The Greater Northwest

It is important to note that this is a larger region than was analyzed in the prior E3 decarbonization work
in the Northwest which only analyzed a “Core Northwest” region consisting of Oregon, Washington,
northern Idaho and Western Montana. The larger footprint encompasses the utilities that have
traditionally coordinated operational efficiencies through programs under the Northwest Power Pool and
includes utilities that typically transact with each other to maintain resource adequacy and optimize
resource portfolios. The larger region also incorporates a footprint that allows for diversity of both load
and resources which minimizes the need for firm capacity. The Balancing Authority Areas (BAAs) that were
included in this Greater Northwest study region are listed in Table 2.
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Table 2: List of Balancing Authorities Included in Study
Balancing Authority Areas Included in Greater Northwest Study Region
Avista Bonneville Power
Administration
Chelan County PUD
Douglas County PUD Grant County PUD Idaho Power
NorthWestern PacifiCorp East PacifiCorp West
Portland General
Electric
Puget Sound Energy Seattle City Light
Tacoma Power Western Area Power
Administration Upper
Great Plains

3.3 Scenarios & Sensitivities
This study examines the resource adequacy requirements of the Greater Northwest region across multiple
timeframes and decarbonization scenarios.
 Near-term (2018) reliability statistics are calculated for today’s system based on 2018 existing
loads and resources. These results are presented to give the reader a sense of existing challenges
and as a reference for other scenario results.
 Medium-term (2030) reliability statistics are calculated in 2030 for two scenarios: a Reference
scenario and a No Coal scenario. The Reference scenario includes the impact of expected load
growth and announced generation retirements, notably the Boardman, Centralia, and Colstrip
coal plants. The No Coal scenario assumes that all coal is retired.
 Long-term (2050) reliability statistics are calculated in 2050 for multiple scenarios including a
Reference scenario and for a range of decarbonization targets. The Reference scenario includes
the impact of load growth, growth in renewable capacity to meet current RPS policy goals, and
the retirement of all coal. Decarbonization scenarios assume GHG emissions are reduced to 60%,
80%, 90%, 98% and 100% below 1990 GHG levels through the addition of wind, solar, and electric
energy storage.
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These scenarios are summarized in Table 3.
Table 3: List of Scenarios and Descriptions
Analysis Period Scenario Description
Near-term (2018) Reference 2018 Existing Loads and Resources
Medium-Term
(2030)
Reference Includes load growth through 2030 and announced
generation retirements, notably the Boardman,
Centralia, and Colstrip coal plants
No Coal Same as 2030 reference but all coal generation in
the region is retired (11 GW)
Long-Term (2050) Reference Includes load growth through 2050, renewable
capacity additions to meet RPS targets, and
retirement of all coal generation (11 GW)
60% GHG Reduction
Scenarios achieve specified greenhouse gas
reduction (relative to 1990 levels) through addition
of solar, wind, and energy storage; sufficient gas
generating capacity is maintained to ensure
reliability (except in 100% GHG Reduction)
80% GHG Reduction
90% GHG Reduction
98% GHG Reduction
100% GHG Reduction
This study further explores the potential resource adequacy needs of a 100% carbon free electricity
system in 2050 recognizing that emerging technologies beyond wind, solar, and electric energy storage
that are not yet available today may come to play a significant role in the region’s energy future. To better
understand how those technologies might impact the viability of achieving this ambitious goal, the study
includes several sensitivity analyses of the 100% GHG Reduction scenario that assume the wide-scale
availability of several such emerging technology options. These sensitivities are described in Table 4.
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Table 4: 100% GHG Reduction in 2050 Sensitivities
Sensitivity Name Description
Clean Baseload Assesses the impact of technology that generates reliable baseload
power with zero GHG emissions. This scenario might require a
technology such as a small modular nuclear reactor (SMR), fossil
generation with 100% carbon capture and sequestration, or other
undeveloped or commercially unproven technology.
Ultra-Long Duration Storage Assesses the impact of an ultra-long duration electric energy storage
technology (e.g., 100’s of hours) that can be used to integrate wind
and solar. This technology is not commercially available today at
reasonable cost.
Biogas Assesses the impact of a GHG free fuel (e.g., biogas, renewable natural
gas, etc.) that could be used with existing dispatchable generation
capacity.
3.4 Key Portfolio Metrics
Each of the scenarios is evaluated using several different metrics which are defined below:
3.4.1 CLEAN ENERGY METRICS
A number of metrics are used to characterize the greenhouse gas content of generation within the region
in each of the scenarios. These are:
 Greenhouse Gas Emissions (MMT CO2): the annual quantity of greenhouse gas emissions
attributed to ratepayers of the Greater Northwest region, measured in million metric tons.
 Greenhouse Gas Reduction (%): the reduction below 1990 emission levels (approximately 60
million metric tons) for the Greater Northwest region.
 Clean Portfolio Standard (%): the total quantity of GHG-free generation (including renewable,
hydro, and nuclear) divided by retail electricity sales. Because this metric allows the region to
retain the clean attribute for exported electricity and offset in-region or imported natural gas
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generation, this metric can achieve or exceed 100% without reducing GHGs to zero. This metric is
presented because it is a common policy target metric across many jurisdictions to measure clean
energy progress and is the near-universal metric used for state-level Renewables Portfolio
Standards. This metric is consistent with California’s SB 100 which mandates 100% clean energy
by 2045.
 GHG-Free Generation (%): the total quantity of GHG-free generation, minus exported GHG-free
generation, divided by total wholesale load. For this metric, exported clean energy cannot be
netted against in-region or imported natural gas generation. When this metric reaches 100%, GHG
emissions have been reduced to zero.
3.4.2 COST METRICS
 Renewable Curtailment (%): the total quantity of wind and solar generation that cannot be
delivered to loads in the region or exported, expressed as a share of total available potential
generation from wind and solar resources.
 Annual Cost Delta ($B) is the annual cost in 2050 of decarbonization scenarios relative to the 2050
Reference scenario. While the 2050 Reference scenario will require significant costs to meet load
growth, this metric only evaluates the change in costs for each decarbonization scenario relative
to the Reference scenario. By definition, the 2050 Reference scenario has an annual cost delta of
zero. The annual cost delta is calculated by comparing the incremental cost of new wind, solar,
and storage resources to the avoided cost of natural gas capital and operational costs.
 Additional Cost ($/MWh) is the total annual cost delta ($B) divided by total wholesale load, which
provides an average measure of the incremental rate impact borne by ratepayers within the
region. While this metric helps to contextualize the annual cost delta, it is important to note that
the incremental cost will not be borne equally by all load within the Greater Northwest region
and some utilities may experience higher additional costs.
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3.5 Study Caveats
3.5.1 COST RESULTS
The study reports the incremental costs of achieving various GHG targets relative to the cost of the
reference scenario. While the method used to estimate capital and dispatch costs is robust, it does not
entail optimization and the results should be regarded as high-level estimates. For this reason, a range of
potential incremental costs are reported rather than a point estimate. The range is determined by varying
the cost of wind, solar, energy storage and natural gas.
3.5.2 HYDRO DISPATCH
For this study, RECAP utilizes a range of hydro conditions based on NWPCC data covering the time period
1929 – 2008. Within each hydro year, hydroelectric energy “budgets” for each month are allocated to
individual weeks and then dispatched to minimize net load, subject to sustained peaking limit constraints
that are appropriate for the water conditions. Hydro resources are dispatched optimally within each week
with perfect foresight. There are many real-life issues such as biological conditions, flood control,
coordination between different project operators, and others that may constrain hydro operations further
than what is assumed for this study.
3.5.3 TRANSMISSION CONSTRAINTS
This analysis treats the Greater Northwest region as one zone with no internal transmission constraints
or transactional friction. In reality, there are constraints in the region that may prevent a resource in one
corner of the region from being able to serve load in another corner. To the extent that constraints exist,
the Greater Northwest region may be less resource adequate than is calculated in this study and additional
effective capacity would be required to achieve the calculated level of resource adequacy. It is assumed
that new transmission can be developed to deliver energy from new renewable resources to wherever it
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is needed, for a cost that is represented by the generic transmission cost adder applied to resources in
different locations.
3.5.4 INDIVIDUAL UTILITY RESULTS
Cost and resource results in this study are presented from the system perspective and represent an
aggregation of the entire Greater Northwest region. These societal costs include all capital investment
costs (i.e., “steel in the ground”) and operational costs (i.e., fuel and operation and maintenance) that are
incurred in the region. The question of how these societal costs are allocated between individual utilities
is not addressed in this study, but costs for individual utilities may be higher or lower compared to the
region as a whole. Utilities with a relatively higher composition of fossil resources today are likely to bear
a higher cost than utilities with a higher composition of fossil-free resources.
Resource adequacy needs will also be different for each utility as individual systems will need a higher
planning reserve margin than the Greater Northwest region as a whole due to smaller size and less
diversity. The capacity contribution of renewables will be different for individual utilities due to
differences in the timing of peak loads and renewable generation production.
3.5.5 RENEWABLE RESOURCE AVALIBILITY AND LAND USE
The renewable resource availability assumed for this study is based on technical potential as assessed by
NREL. It is assumed wind and solar generation can be developed in each location modeled in this study up
to the technical potential. However, the land consumption is significant for some scenarios and it is not
clear whether enough suitable sites can be found to develop the large quantities of resources needed for
some scenarios. Land use is also a significant concern for the new transmission corridors that would be
required.

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4 Key Inputs & Assumptions
4.1 Load Forecast
The Greater Northwest region had an annual load of 247 TWh and peak load of 43 GW in 2017. This data
was obtained by aggregating hourly load data from the Western Electric Coordinating Council (WECC) for
each of the selected balancing authority areas in the Greater Northwest region.
This study assumes annual load growth of 1.3% pre-energy efficiency and 0.7% post-energy efficiency.
This assumption is consistent with the previous E3 decarbonization work for Oregon and Washington and
is benchmarked to multiple long-term publicly available projections listed in Table 5. The post-energy
efficiency growth rate includes the impact of all cost-effective energy efficiency identified by the NWPCC,
scaled up to the full Greater Northwest region and assumed to continue beyond the end of the Council’s
time horizon. Electrification of vehicles and buildings is only included to the extent that it is reflected in
these load growth forecasts. For example, the NWPCC forecast includes the impact of 1.1 million electric
vehicles by 2030.
In general, E3 believes these load growth forecasts are conservatively low because they exclude the effect
of vehicle and building electrification that would be expected in a deeply decarbonized economy. To the
extent that electrification is higher than forecasted in this study, resource adequacy requirements would
also increase. In this study, total loads increase 25% by 2050, whereas other studies 12 that have
comprehensively examined cost-effective strategies for economy-wide decarbonization include
12 https://www.ethree.com/wp-content/uploads/2018/06/Deep_Decarbonization_in_a_High_Renewables_Future_CEC-500-2018-012-1.pdf
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significant quantities of building, vehicle, and industry electrification that cause electricity-sector loads to
grow by upwards of 60% by 2050 even with significant investments in energy efficiency.
Table 5. Annual load growth forecasts for the Northwest
Source Pre EE Post EE
PNUCC Load Forecast 1.7% 0.9%
BPA White Book 1.1% -
NWPCC 7th Plan 0.9% 0.0%
WECC TEPPC 2026 Common Case - 1.3%
E3 Assumption 1.3% 0.7%
Hourly load profiles are assumed to be constant through the analysis period and do not account for any
potential impact due to electrification of loads or climate change. The Greater Northwest system is a
winter peaking system with loads that are highest during cold snaps on December and January mornings
and evenings. An illustration of the average month/hour load profile for the Greater Northwest is shown
in Figure 4.
Figure 4: Month/Hour Average Hourly Load in the Greater Northwest (GW)

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Projecting these hourly loads using the post-energy efficiency load growth forecasts yields the following
load projections in 2030 and 2050.
Table 6. Load projections in 2030 and 2050 for the Greater NW Region
Load 2018 2030 2050
Median Peak Load (GW) 43 47 54
Annual Energy Load (TWh) 247 269 309

To evaluate the reliability of the Greater Northwest system under a range of weather conditions, hourly
load forecasts for 2030 and 2050 are developed over seventy years of weather conditions (1948-2017).
Historical weather data was obtained from the National Oceanic and Atmospheric Administration (NOAA)
for the following sites in the Greater Northwest region.
Table 7: List of NOAA Sites for Historical Temperature Data
City Site ID
Billings, MT USW00024033
Boise, ID USW00024131
Portland, OR USW00024229
Salt Lake City, UT USW00024127
Seattle, WA USW00024233
Spokane, WA USW00024157
4.2 Existing Resources
A dataset of existing generating resources in the Greater Northwest was derived from two sources: 1) the
NWPCC’s GENESYS model, used to characterize all plants within the Council’s planning footprint; and 2)
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the WECC’s Anchor Data Set, used to gather input data for all existing plants in areas outside of the
NWPCC’s footprint. For each resource, the dataset contains:
 Dependable capacity (MW)
 Location
 Commission and announced retirement date
 Forced outage rate (FOR) and mean time to repair (MTTR)
A breakdown of existing resources by type is shown in Figure 5.
Figure 5: Existing 2018 Installed Capacity (MW) by Resource Type

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Several power plants have announced plans to retire one or more units. The table below lists the notable
coal and natural gas planned retirements through 2030.
Table 8: Planned Coal and Natural Gas Retirements
Power Plant Resource Type Capacity (MW)
Boardman Coal 522
Centralia Coal 1,340
Colstrip 1 & 2 Coal 614
North Valmy Coal 261
Naughton Natural Gas 330
4.2.1 WIND AND SOLAR PROFILES
Hourly wind and solar data were collected for each existing resource in the combined dataset at the
location of the resource. For wind, NREL’s Wind Integration National Dataset Toolkit was used which
includes historical hourly wind speed data from 2007-2012. For solar, NREL’s Solar Prospector Database
was used which includes historical hourly solar insolation data from 1998-2012. These hourly wind speeds
and solar insolation values were then converted into power generation values using the NREL System
Advisor Model (SAM) under assumptions for wind turbine characteristics (turbine power curve and hub
height) and solar panel characteristics (solar inverter ratio). RECAP simulates future electricity generation
from existing wind and solar resources using the historical wind speed data and solar insolation data
respectively.
Simulated wind generation from existing wind plants within BPA territory was benchmarked to historical
wind production data13. To simulate wind generation from existing plants accurately, wind turbine
13 BPA publishes production from wind plants within its Balancing Authority Area in 5-min increments:
https://transmission.bpa.gov/Business/Operations/Wind/default.aspx
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technology (power curve and hub height) varies for each existing wind farm, based on the year of
installation. Figure 6 shows how the simulated wind production compares to historical wind production
in BPA territory in January 2012.
Figure 6: Comparison of historical wind generation to simulated wind production for January 2012

A detailed description of the renewable profile simulation process is described in Appendix C.
4.2.2 HYDRO
Hydro availability is based on a random distribution of the historical hydro record using the water years
from 1929-2008. This data was obtained from the NWPCC’s GENESYS model. Future electricity generation
from existing hydro resources is simulated using the historical hydro availability. Available hydro energy
is dispatched in RECAP subject to sustained peaking limits (1-hr, 2-hr, 4-hr, 10-hr) and minimum output
levels. The sustained peaking limits are based on detailed hydrological models developed by NWPCC.
Available hydro budgets, sustained peaking limits, and minimum output levels are shown for three hydro
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years – 1937 (critical hydro year), 1996 (high hydro year), and 2007 (typical hydro year). The 10-hour
sustained peaking limits for each month represent the maximum average generation for any continuous
10-hour period within the month.
Figure 7: Monthly budgets, sustained peaking limits and minimum outputs levels for 1937 (critical hydro)

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Figure 8: Monthly budgets, sustained peaking limits and minimum outputs levels for 1996 (high hydro)

Figure 9: Monthly budgets, sustained peaking limits and minimum outputs levels for 2007 (typical hydro)

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4.2.3 IMPORTS/EXPORTS
The Greater Northwest region is treated as one zone within the model, but it does have the ability to
import and export energy with neighboring regions, notably California, Canada, Rocky Mountains, and the
Southwest. Import and export assumptions used in this model are consistent with the NWPCC’s GENESYS
model and are listed in Table 9. Monthly and hourly import availabilities are additive but in no hour can
exceed the simultaneous import limit of 3,400 MW. In the 100% GHG Reduction scenarios, import
availability is set to zero to prevent the region from relying on fossil fuel imports.
Table 9: Import Limits
Import Type Availability MW
Monthly Imports
Nov – Mar 2,500
Oct 1,250
Apr – Sep -
Hourly Imports HE 22 – HE 5 3,000
HE 5 – HE 22 -
Simultaneous Import Limit All Hours 3,400
For the purposes of calculating the CPS % metric i.e., “clean portfolio standard”, the model assumes an
instantaneous exports limit of 7,200 MW in all hours.
Table 10: Export Limit
Export Type Availability MW
Simultaneous Export Limit All Hours 7,200
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4.3 Candidate Resources
Candidate resources are used to develop portfolios of resources in 2050 to both achieve GHG reduction
targets or ensure acceptable reliability of 2.4 hrs./yr. LOLE. For a more detailed description of the portfolio
development process, see Section 3.1.3. The 7 candidate resources are:
 Solar (geographically diverse across Greater Northwest)
 Northwest Wind (WA/OR)
 Montana Wind
 Wyoming Wind
 4-Hour Storage
 8-Hour Storage
 16-Hour Storage
Natural gas generation is also added as needed to meet any remaining reliability gaps after the GHG
reduction target is met. The new renewable candidate resources (solar, NW wind, MT wind, WY wind)
are assumed to be added proportionally across a geographically diverse footprint which has a strong
impact on the ability of variable renewable resources to provide reliable power that can substitute for
firm generation. Figure 10 illustrates the location of new candidate renewable resources. When a resource
is added, it is added proportionally at each of the locations shown in the figure below.
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Figure 10: New Renewable Candidate Resources

The generation output profile for each location was simulated by gathering hourly wind speed and solar
insolation data from NREL’s Wind Integration National Dataset Toolkit and Solar Prospector Database and
converting to power output using NREL’s System Advisor Model. The wind profiles used in this study are
based on 135 GW of underlying wind production data from hundreds of sites. The solar profiles used in
this study are based on 80 GW of underlying solar production data across four states. This process is
described in more detail in Appendix C.
New storage resources are available to the model in different increments of duration at different costs
which provide different value in terms of both reliability and renewable integration for GHG reduction.
Note that the model can choose different quantities of each storage duration which results in a fleet-wide
storage duration that is different than any individual storage candidate resource. Because storage is
modeled in terms of capacity charge/discharge and duration, many different storage technologies could
provide this capability. The cost forecast trajectory for Li-Ion battery storage was used to estimate costs,
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but any storage technology that could provide equivalent capacity and duration, such as pumped hydro
or flow batteries, could substitute for the storage included in the portfolio results of this study.
New renewable portfolios are within the bounds of current technical potential estimates published in
NREL.
Table 11. NREL Technical Potential (GW)
State Wind Technical Potential (GW)
Washington 18
Oregon 27
Idaho 18
Montana 944
Wyoming 552
Utah 13
Total 1,588
4.3.1.1 Resource Costs
All costs in this study are presented in 2016 dollars. The average cost of each resource over the 2018-2050
timeframe is shown in Table 12 while the annual cost trajectories from 2018-2050 are shown in Figure 11.
Table 12. Resource Cost Assumptions (2016 $)
Technology Unit High14 Low15 Transmission Notes
Solar PV $/MWh $59 $32 $8 Capacity factor = 27%
NW Wind $/MWh $55 $43 $6 Capacity factor = 37%
MT/WY Wind $/MWh $48 $37 $19 Capacity factor = 43%
4-hr Battery $/kW-yr $194 $97
14 Source for high prices: 2017 E3 PGP Decarbonization Study
15 Source for low prices: NREL 2018 ATB Mid case for wind and solar; Lazard LCOS Mid case 4.0 for batteries
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Technology Unit High14 Low15 Transmission Notes
8-hr Battery $/kW-yr $358 $189
16-hr Battery $/kW-yr $686 $373
Natural Gas Capacity $/kW-yr $150 $150 7,000 Btu/kWh heat rate; $5/MWh variable O&M
Gas Price $/MMBtu $4 $2
Biogas Price $/MMBtu $39 $39

Figure 11: Cost trajectories over the 2018-2050 timeframe (2016 $)

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4.4 Estimating Cost and GHG Metrics
The cost of the future electricity portfolios consists of (1) fixed capital costs for building new resources,
and (2) operating costs for running both existing and new resources. For new wind and new solar
resources, the cost of generation is calculated using their respective levelized costs (see Table 12). Cost of
electricity generation from natural gas plants includes both the capital cost for new natural gas plants and
the operating costs (fuel costs and variable operating costs). All the natural gas plants are assumed to
operate at a heat rate of 7,000 Btu/kWh, with the price of natural gas varying from $2 to $4 per MMBtu
(see Table 12). Storage resources are assumed to have only fixed cost, but no operating cost. All exports
are assumed to yield revenues of $30 per MWh.
In this study, annual GHG emissions are compared against 1990 emission levels, when the emissions for
the Greater Northwest region was 60 million metric tons. GHG emissions are calculated for each thermal
resource depending on the fuel type. For natural gas plants, an emission rate of 117 lb. of CO2 per MMBtu
of natural gas is assumed, yielding 0.371 metric tons of CO2 per MWh of electricity generated from natural
gas (assumed 7,000 Btu/kWh heat rate). For coal plants, an emission rate of 1.0 ton of CO2 per MWh of
electricity generated from coal is assumed.
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5 Results
5.1 Short-Term Outlook (2018)
The 2018 system (today’s system) in the study region is supplied by a mix of various resources, as
described in Section 4.2. The annual electricity load for the study region is 247 TWh with a winter peak
demand of 43 GW. Hydro energy provides the plurality of generation capacity with significant
contributions from natural gas, coal and wind generation.
Resource adequacy conclusions vary depending on what metric is used for evaluation. The region has
sufficient capacity to meet the current standard used by the NWPCC of 5% annual loss of load probability
(LOLP). The region does not have sufficient capacity to meet the 2.4 hrs./yr. LOLE standard used in this
study. In other words, most loss of load is concentrated in a few number of years which matches intuition
for a system that is dependent upon the annual hydro cycle and susceptible to drought conditions. Full
reliability statistics for the Greater Northwest region are shown in Table 13.
Table 13. 2018 Reliability Statistics
Metric Units Value
Annual LOLP (%) % 3.7%
Loss of Load Expectation (LOLE) hrs/yr 6.5
Expected Unserved Energy (EUE) MWh/yr 5,777
Normalized EUE % 0.003%
1-in-2 Peak Load GW 43
PRM Requirement % of peak 12%
Total Effective Capacity Requirement GW 48

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Table 14. 2018 Load and Resource Balance

In order to meet an LOLE target of 2.4 hrs./yr., a planning reserve margin (PRM) of 12% is required. The
PRM is calculated by dividing the quantity of effective capacity needed to meet the LOLE target by the
median peak load, then subtracting one. This result is lower than many individual utilities currently hold
within the region (typical PRM ~15%) due to the load and resource diversity across the geographically
large Greater Northwest region. As shown in Table 14, the total effective capacity (47 GW) available is
slightly lower than the total capacity requirement (48 GW) which is consistent with the finding that the
Load Load GW
Peak Load 42.1
Firm Exports 1.1
PRM (12%) 5.2
Total Requirement 48.4
Resources Nameplate GW Effective % Effective GW
Coal 10.9 100% 10.9
Gas 12.2 100% 12.2
Biomass & Geothermal 0.6 100% 0.6
Nuclear 1.2 100% 1.2
Demand Response 0.6 50% 0.3
Hydro 35.2 53% 18.7
Wind 7.1 7% 0.5
Solar 1.6 12% 0.2
Storage 0 — 0
Total Internal Generation 69.1 44.7
Firm Imports 3.4 74% 2.5
Total Supply 72.5 47.2
Surplus/Deficit
Capacity Surplus/Deficit -1.2
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system is not sufficiently reliable to meet a 2.4 hrs./yr. LOLE target. The effective capacity percent
contributions from wind and solar are shown to be 7% and 12%, respectively. These relatively low values
stem primarily from the non-coincidence of wind and solar production during high load events in the
Greater Northwest region, notably very cold winter mornings and evenings.
It should be noted that the effectiveness of firm capacity is set to 100% by convention in calculating a
PRM. The contribution of variable resources is then measured relative to firm capacity, incorporating the
effect of forced outage rates for firm resources.
5.2 Medium-Term Outlook (2030)
The Greater Northwest system in 2030 is examined under two scenarios:
 Reference
• Planned coal retirements; new gas gen for reliability
 No Coal
• All coal retired; new gas gen for reliability
The resulting generation portfolios in both scenarios (both of which meet the 2.4 hrs./yr. LOLE reliability
standard) are shown in Figure 12 alongside the 2018 system for context. To account for the load growth
by 2030, 5 GW of net new capacity is required to maintain reliability. In the Reference Scenario where 3
GW of coal is retired, 8 GW of new firm capacity is needed by 2030 for reliability. Similarly, the No Coal
Scenario (where all 11 GW of coal is retired) results in 16 GW of new firm capacity need by 2030. The
study assumes all the new capacity in the 2030 timeframe need is met through additional natural gas
build. It should be noted that regardless of what resource mix is built to replace the retirement of coal,
the siting, permitting, and construction of these new resources will take significant time so planning for
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these resources needs to begin well before actual need. The portfolio tables for each scenario are
summarized in Appendix A.2.
Figure 12: Generation Portfolios in 2030

Table 15. 2030 Generation Portfolio: Key Metrics
Metric 2030 Reference 2030 No Coal
GHG-Free Generation (%) 61% 61%
GHG Emissions (MMT CO2 / year) 67 42
% GHG Reduction from 1990 Level -12%16 31%
16 Negative value for %GHG reduction from 1990 level indicates that emissions are above 1990 level
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As these metrics show, without either natural gas replacement of coal capacity or significant increase in
renewable energy, GHG emissions are forecasted to rise in the 2030 timeframe. However, repowering
coal with natural gas has the potential to reduce GHG emissions by 31% below 1990 levels.
In order to meet an LOLE target of 2.4 hrs/yr, the region requires a planning reserve margin (PRM) in 2030
of 12%.
Table 16. 2030 Load and Resource Balance, Reference Scenario
Load Load MW
Peak Load 45.9
Firm Exports 1.1
PRM (12%) 5.8
Total Requirement 52.9
Resources Nameplate MW Effective % Effective MW
Coal 8.2 100% 8.2
Gas 19.9 100% 19.9
Bio/Geo 0.6 100% 0.6
Nuclear 1.2 100% 1.2
DR 2.2 45% 1.0
Hydro 35.2 53% 18.7
Wind 7.1 9% 0.6
Solar 1.6 14% 0.2
Storage 0 — 0
Total Internal Generation 76.1 50.5
Firm Imports 3.4 74% 2.5
Total Supply 79.5 52.9
Surplus/Deficit
Capacity Surplus/Deficit 0.0
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5.3 Long-Term Outlook (2050)
The Greater Northwest system in 2050 is examined under a range of decarbonization scenarios, relative
to 1990 emissions.
 60% GHG Reduction
 80% GHG Reduction
 90% GHG Reduction
 98% GHG Reduction
 100% GHG Reduction
The portfolio for each decarbonization scenario was developed using the methodology described in
Section 3.1.3. To summarize this process, RECAP iteratively adds carbon-free resources (wind, solar
storage) to reduce GHG in a manner that maximizes the effective capacity of these carbon-free resources,
thus minimizing the residual need for firm natural gas capacity. Once a cost-effective portfolio of carbon-
free resources has been added to ensure requisite GHG reductions, the residual need for natural gas
generation capacity is calculated to ensure the entire portfolio meets a 2.4 hrs./yr. LOLE standard.
5.3.1 ELECTRICITY GENERATION PORTFOLIOS
All the 2050 decarbonization portfolios are shown together in Figure 13. Higher quantities of renewable
and energy storage are required to achieve deeper levels of decarbonization, which in turn provide
effective capacity to the system and allow for a reduction in residual firm natural gas capacity need,
relative to the reference case. Detailed portfolio results tables for each scenario are provided in Appendix
A.2.
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Figure 13: Generation Portfolios for 2050 Scenarios

Table 17. 2050 Decarbonization Scenarios: Key Generation Metrics
Metric

Reference
Scenario
GHG Reduction Scenarios
Units 60% Red. 80% Red. 90% Red. 98% Red.
100%
Red.
GHG Emissions MMT/yr 50 25 12 6 1 0
GHG Reductions % below
1990 16% 60% 80% 90% 98% 100%
GHG-Free
Generation % of load 60% 80% 90% 95% 99% 100%
Clean Portfolio
Standard % of sales 63% 86% 100% 108% 117% 123%
Annual Renewable
Curtailment
% of
potential Low Low 4% 10% 21% 47%
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Table 17 evaluates the performance of each decarbonization portfolio along several key generation
metrics that were described in detail in Section 3.4.
Analyzing the portfolio of each decarbonization scenario and resulting performance metrics yields several
interesting observations.
 On retiring all 11 GW of coal by 2050 in the Reference scenario, the Greater Northwest system
requires 20 GW of new capacity in order to meet the 2.4 hrs./yr. LOLE standard used in the study.
This suggests that 9 GW of net new firm capacity is needed to account for load growth through
2050.
 The integration of more renewables and conservation policies provides the energy needed to
serve loads in a deeply decarbonized future, but new gas-fired generation capacity is needed for
relatively short, multi-day events with low renewable generation, high loads, and low hydro
availability.
 To reduce GHG emissions to 80% below 1990 levels, RECAP chooses to build 38 GW of wind, 11
GW of solar, and 2 GW of 4-hour storage. In addition to this renewable build, 12 GW of new firm
capacity is required for reliability (after retaining all the existing natural gas plants) which is
assumed to be met through natural gas build. The generation portfolio under 80% Reduction
Scenario results in a 100% clean portfolio standard and 90% GHG-free generation.
 RECAP achieves deeper levels of decarbonization (GHG emissions 98% below 1990 level down to
1.0 MMT GHG/yr) by overbuilding renewables with 54 GW of wind, 29 GW of solar, and 7 GW of
4-hour storage. Annual renewable oversupply becomes significant (at 21%). Nevertheless, the
system still requires an additional gas build of 2 GW after retaining all existing natural gas plants,
to ensure reliability during periods of low renewable generation. The capacity factor for these gas
plants is extremely low (3%), underlining their importance for reliability.
 The 100% GHG Reduction Scenario (Zero Carbon Scenario) results in no GHG emissions from the
electricity sector. The generation portfolio consists only of renewables (97 GW of wind and 46
GW of solar) and energy storage (29 GW of 6-hour storage). Ensuring a reliable system using only
renewables and energy storage requires a significant amount of renewable overbuild – resulting
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in nearly half of all the generated renewable energy to be curtailed. Compared to the 98% GHG
Reduction Scenario (which results in 99% GHG-free generation), the Zero Carbon Scenario
requires almost double the quantity of renewables and even greater quantity of energy storage.
With increases in renewable generation, generation from natural gas plants decreases. Due to negligible
operating costs associated with renewable production, it is cost optimal to use as much renewable
generation as the system can. During periods of prolonged low renewable generation when energy
storage is depleted, natural gas plants can ramp up to provide the required firm capacity to avoid loss-of-
load events. In the deep decarbonization scenarios, gas is utilized sparingly and even results in very low
capacity factors (such as 9% and 3%). However, RECAP chooses to retain (and even build) natural gas as
the most cost-effective resource to provide reliable firm capacity. Renewable overbuild also results in
significant amounts of curtailment.
Figure 14: Annual generation mix across the scenarios

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A planning reserve margin of 7% to 9% is required to meet the 1-in-10 reliability standard in 2050
depending on the scenario. Accounting for a planning reserve margin, the total capacity requirement (load
plus planning reserve margin) in 2050 is 57-59 GW. As shown in Table 18, this capacity requirement is met
through a diverse mix of resources. Variable or energy-limited resources such as hydro, wind, solar and
storage contribute only a portion of their entire nameplate capacity (ELCC) towards resource adequacy.
Load and resource tables for the 80% and 100% Reduction scenarios are shown below.
Table 18. 2050 Load and Resource Balance, 80% Reduction scenario
Load Load MW
Peak Load 52.8
Firm Exports 1.1
PRM (9%) 4.9
Total Requirement 58.8
Resources Nameplate MW Effective % Effective MW
Coal 0 — 0
Gas 23.5 100% 23.5
Bio/Geo 0.6 100% 0.6
Nuclear 1.2 100% 1.2
DR 5.5 29% 1.6
Hydro 35.2 53% 18.7
Wind 38.0 19% 7.2
Solar 10.6 19% 2.0
Storage 2.2 73% 1.6
Total Internal Generation 116.8 56.3
Firm Imports 3.4 74% 2.5
Total Supply 120.2 58.8
Surplus/Deficit
Capacity Surplus/Deficit 0.0
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Table 19. 2050 Load and Resource Balance, 100% Reduction scenario
Load Load MW
Peak Load 52.8
Firm Exports 1.1
PRM (7%) 4.0
Total Requirement 58.0
Resources Nameplate MW Effective % Effective MW
Coal 0 — 0
Gas 0 — 0
Bio/Geo 0.6 100% 0.6
Nuclear 1.2 100% 1.2
DR 5.5 29% 1.6
Hydro 35.2 57% 20.1
Wind 97.4 22% 21.5
Solar 45.6 16% 7.3
Storage 28.7 20% 5.7
Total Internal Generation 214.2 58.0
Firm Imports 0 — 0
Total Supply 214.2 58.0
Surplus/Deficit
Capacity Surplus/Deficit 0.0

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5.3.2 ELECTRIC SYSTEM COSTS
System costs are estimated using the methodology and cost assumptions described in Section 4.3.1.1 and
Section 4.4. Electric system costs represent the cost of decarbonization relative to the 2050 Reference
scenario, and so by definition all annual and unit cost increases in this scenario are zero. The 2050
Reference scenario does require significant investment in new resources in order to reliably meet load
growth and existing RPS policy targets, so the zero incremental cost is not meant to make any assessment
on the absolute change (or lack thereof) in total electric system costs or rates by 2050.
Table 20 evaluates the performance of 2050 decarbonization scenarios along two cost metrics for both a
low and high set of cost assumptions.
Table 20: 2050 Decarbonization Scenarios: Key Cost Metrics
Metric

Reference
Scenario
GHG Reduction Scenarios
Units 60% Red. 80% Red. 90% Red. 98% Red.
100%
Red.
Annual Cost
Increase
Lo $BB/yr
(vs. Ref) —
$0 $1 $2 $3 $16
Hi $2 $4 $5 $9 $28
Unit Cost
Increase
Lo $/MWh
(vs. Ref) —
$0 $3 $5 $10 $52
Hi $7 $14 $18 $28 $89
Analyzing the cost results for each decarbonization scenario yields several interesting observations
 To reduce GHG emissions to 80% below 1990 levels, a portfolio of wind/solar/storage can be
obtained at an additional annual cost of $1 to $4 billion ($3 to $14/MWh) after accounting for the
avoided costs of new gas build and utilization. Assuming an existing average retail rate of
$0.10/kWh, this implies an increase of 3%-14% in real terms relative to the Reference Scenario.
Because the 80% reduction scenario achieves a 100% clean portfolio standard (as shown in
Section 5.3.1), this scenario is compelling from both a policy perspective and a cost perspective in
balancing multiple objectives across the Greater Northwest region.
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 Deep decarbonization (GHG emissions 98% below 1990 level down to 1.0 MMT GHG/yr) of the
Greater Northwest system can be obtained at an additional annual cost of $3 to $9 billion ($10 to
$28/MWh), i.e., the average retail rates increase 10%-28% in real terms relative to the Reference
Scenario. This suggests that deep decarbonization of the Greater Northwest system can be
achieved at moderate additional costs, assuming that natural gas capacity is available as a
resource option to maintain reliability during prolonged periods of low renewable production.
 The 100% GHG Reduction Scenario requires a significant increase in wind, solar and storage to
eliminate the final 1% of GHG-emitting generation. An additional upfront investment of $100
billion to $170 billion is required, relative to the 98% GHG Reduction scenario. Compared to the
Reference Scenario, the Zero Carbon Scenario requires an additional annual cost of $16 to $28
billion ($52 to $89/MWh), i.e., the average retail rates nearly double.
Costs for individual utilities will vary and may be higher or lower than the region as a whole. This report
does not address allocation of cost between utilities.
As shown in Figure 15, the cost increases of achieving deeper levels of decarbonization become
increasingly large as GHG emissions approach zero. This is primarily due to the level of renewable
overbuild that is required to ensure reliability and the increasing quantities of energy storage required to
integrate the renewable energy.
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Figure 15: Cost of GHG reduction

The marginal cost of GHG reduction represents the incremental cost of additional GHG reductions at
various levels of decarbonization. Figure 16 and Figure 17 both show the increasing marginal cost of GHG
abatement at each level of decarbonization. At very deep levels of GHG reductions, the marginal cost of
carbon abatement greatly exceeds the societal cost of carbon emissions, which generally ranges from
$50/ton to $250/ton17, although some academic estimates range up to $800/ton18.
17 https://19january2017snapshot.epa.gov/climatechange/social-cost-carbon_.html
18 https://www.nature.com/articles/s41558-018-0282-y
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Figure 16: Marginal Cost of GHG Reduction: 60% Reduction To 98% Reduction

Figure 17: Marginal Cost of GHG Reduction: 60% Reduction to 100% Reduction

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5.3.3 DRIVERS OF RELIABILITY CHALLENGES
The major drivers of loss of load in the Greater Northwest system include high load events, prolonged low
renewable generation events, and drought hydro conditions. In today’s system where most generation is
dispatchable, prolonged low renewable generation events do not constitute a large cause of loss-of-load
events. Rather, the largest cause of loss-of-load events stem from the combination of high load events
and drought hydro conditions. This relationship between contribution to LOLE and hydro conditions is
highlighted in Figure 18 which shows nearly all loss of load events concentrated in the worst 25% of hydro
years.
Figure 18. 2018 System Loss-of-Load Under Various Hydro Conditions

At very high renewable penetrations, in contrast, prolonged low renewable generation events usurp
drought hydro conditions as the primary driver of reliability challenges. Figure 19 shows that at high levels
of GHG reductions, loss-of-load is much less concentrated in the worst hydro years as prolonged low
renewable generation events can create loss-of-load conditions in any year.
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Figure 19. 2018 System GHG Reduction Scenarios Loss-of-Load Under Various Hydro Conditions

In practice, these prolonged periods of low renewable output manifest via multi-day winter storms that
inhibit solar production over very wide geographic areas or large-scale high-pressure systems associated
with low wind output. Figure 20 presents an example of multiday loss-of-load in a sample week in 2050
in the 100% GHG Reduction scenario. In a system without available dispatchable resources to call during
such events, low solar radiation and wind speed can often give rise to severe loss-of-load events, especially
when renewable generation may be insufficient to serve all load and storage quickly depletes. As shown
in the example, over 100 GW of total installed renewables can only produce less than 10 GW of output in
some hours. It is the confluence of events like these that drive the need for renewable overbuild to
mitigate these events, which in turn leads to the very high costs associated with ultra-deep
decarbonization.
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Figure 20: Loss-of-load Example in a Sample Week

5.3.4 ROLE OF NATURAL GAS GENERATION CAPACITY
The significant buildout of renewables and storage to meet decarbonization targets contributes to the
resource adequacy needs of the system and reduces the need for thermal generation. However, despite
the very large quantities of storage and renewables in all the high GHG reduction scenarios, a significant
amount of natural gas capacity is still needed for reliability (except for the 100% GHG Reduction scenario
where natural gas combustion is prohibited). Even though the system retains significant quantities of gas
generation capacity for reliability, the capacity factor utilization of the gas fleet decreases substantially at
higher levels of GHG reductions as illustrated in Figure 21. It is noteworthy that all scenarios except 100%
GHG reductions require more gas capacity than exists in 2018, assuming all coal (11 GW) is retired.
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Figure 21: Natural Gas Required Capacity in Different 2050 Scenarios

5.3.5 EFFECTIVE LOAD CARRYING CAPABILITY
Effective Load Carrying Capability (ELCC) is a metric used in the electricity industry to quantify the
additional load that can be met by an incremental generator while maintaining the same level of system
reliability. Equivalently, ELCC is a measure of ‘perfect capacity’ that could be replaced or avoided with
dispatch-limited resources such as wind, solar, storage, or demand response.
5.3.5.1 Wind ELCC
Wind resources in this study are grouped and represented as existing Northwest (Oregon and
Washington) wind, new Northwest wind, and new Wyoming and Montana wind. The ELCC curves of each
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representative wind resource and as well as the combination of all three resources (i.e., “Diverse”) are
shown in Figure 22.
Figure 22: Wind ELCC at Various Penetrations

These results are primarily driven by the coincidence of wind production and high load events. Existing
wind in the Northwest today, primarily in the Columbia River Gorge, has a strong negative correlation with
peak load events that are driven by low pressures and cold temperatures. Conversely, Montana and
Wyoming wind does not exhibit this same correlation and many of the highest load hours are positively
correlated with high wind output as illustrated in Figure 23.
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Figure 23: Load and Wind Correlation (Existing NW Wind and New MT/WY Wind)

Comparing and contrasting the ELCC of different wind resources yields several interesting findings:
 The wide discrepancy between the “worst” wind resource (existing NW) and the “best” wind
resource (new MT/WY) is primarily driven by the correlation of the wind production and peak
load events in Washington and Oregon. Existing NW wind is almost entirely located within the
Columbia River Gorge which tends to have very low wind output during the high-pressure weather
systems associated with the Greater Northwest cold snaps that drive peak load events.
Conversely, MY/WY wind is much less affected by this phenomenon due largely to geographic
distance, and wind output tends to be highest during the winter months when the Northwest is
most likely to experience peak load events.
 All wind resources experience significant diminishing returns at high levels of penetration. While
wind may generate significant energy during the system peak, ultimately the net load peak that
drives ELCC will shift to an hour with low wind production and reduce the effectiveness with which
wind can provide ELCC. Diversity mitigates the rate of decline of ELCC.
 New NW wind has notably higher ELCC values than existing NW wind due to both improvements
in turbine technology but also through larger geographic diversity of wind development within
the Northwest region but outside of the Columbia River Gorge.
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 Diverse wind (combination of all three wind groups) yields the highest ELCC values at high
penetrations. This is because even the best wind resources experience periods of low production
and additional geographic diversity can help to mitigate these events and improve ELCC.
5.3.5.2 Solar ELCC
Solar resources in this study are grouped and represented as existing solar and new solar which is built
across the geographically diverse area of Idaho, Washington, Oregon, and Utah. In general, solar provides
lower capacity value than wind due to the negative correlation between winter peak load events and solar
generation which tends to be highest in the summer. Like wind, solar ELCC also diminishes as more
capacity is added. Figure 24 shows this information for the ELCC of new solar in the Greater Northwest
region.
Figure 24: Solar ELCC at Various Penetrations

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5.3.5.3 Storage ELCC
At small initial penetrations, energy storage can provide nearly 100% ELCC as a substitute for peaking
generation that only needs to discharge for a small number of hours. However, at higher penetrations,
the required duration for storage to continue to provide ELCC to the system diminishes significantly. This
is primarily due to the fact that storage does not generate energy and ELCC is a measure of perfect capacity
which can reliably generate energy. This result holds true for both shorter duration (6-hr) and longer
duration (12-hr) storage which represents the upper end of duration for commercially available storage
technologies. Figure 25 highlights the steep diminishing returns of storage toward ELCC.
Figure 25: Storage ELCC at Various Penetrations

This steeply-declining ELCC value for diurnal energy storage is particularly acute in the Pacific Northwest.
This has to do with the fact that there is a significant quantity of energy storage implicit with the 35-GW
hydro system in the region. The Federal Columbia River Power System is already optimized over multiple
days, weeks and months within the bounds of non-power constraints such as flood control, navigation
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and fish & wildlife protections. Significant quantities of energy are stored in hydroelectric reservoirs today
and dispatched when needed to meet peak loads. Thus, additional energy storage has less value for
providing resource adequacy in the Northwest than it does in regions that have little or no energy storage
today.
5.3.5.4 Demand Response ELCC
Demand response (DR) represents a resource where the system operator can call on certain customers
during times of system stress to reduce their load and prevent system-wide loss-of-load events. However,
DR programs have limitations on how often they can be called and how long participants respond when
they are called. DR in this study is represented as having a maximum of 10 calls per year with each call
lasting a maximum of 4 hours. This is a relatively standard format for DR programs, although practice
varies widely across the country. This study also assumes perfect foresight of the system operator such
that a DR call is never “wasted” when it wasn’t actually needed for system reliability.
Figure 26: Cumulative and Marginal ELCC of DR

Figure 26 shows the cumulative and marginal ELCC of DR at increasing levels of penetration. Due to the
limitations on the number of calls and duration of each call, DR has an initial ELCC of approximately 50%.
Similar to energy storage, conventional 4-hour DR has less value in the Pacific Northwest than in other
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regions due to the flexibility inherent in the hydro system. Also, the capacity value of DR declines as the
need for duration becomes longer and longer.
5.3.5.5 ELCC Portfolio Effects
Grouping different types of renewable resources, energy storage, and DR together often creates synergies
between the different resources such that the combined ELCC of the entire portfolio is more than the sum
of any resource’s individual contribution. For example, solar generation can provide the energy that
storage needs to be effective and storage can provide the on-demand dispatchability that solar needs to
be effective. This resulting increase in ELCC is referred to as the diversity benefit.
Figure 27 shows the average ELCC for each resource type both on a stand-alone basis and also with a
diversity allocation that accrues to each resource when they are added to a portfolio together.

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Figure 27: ELCC of Solar, Wind, and Storage with Diversity Benefits

Figure 28 presents the cumulative portfolio ELCC of wind, solar, and storage up to the penetrations
required to reliably serve load in a 100% GHG Reduction scenario. At high penetrations of renewables and
storage, most of the ELCC is realized through diversity, although it still requires approximately 170 GW of
nameplate renewable and storage resources to provide an equivalent of 37 GW of firm ELCC capacity that
is required to retire all fossil generation. However, unlike adding these resources on a standalone basis, a
combined portfolio continues to provide incremental ELCC value of approximately 20% of nameplate even
at very high levels of penetration.
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Figure 28: ELCC of Different Portfolios in 2050

5.3.6 SENSITIVITY ANALYSIS
This study also explores the potential resource adequacy needs of a 100% GHG free electricity system
recognizing that emerging technologies beyond wind, solar, and electric energy storage that are not yet
available today may come to play a significant role in the region’s energy future. Specifically, the
alternative resources analyzed are: clean baseload, ultra-long duration storage, and biogas which are
further described in Table 21.
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Table 21: Sensitivity Descriptions
Sensitivity Name Description
Clean Baseload Assesses the impact of technology that generates reliable baseload
power with zero GHG emissions. This scenario might require a
technology such as a small modular nuclear reactor (SMR), fossil
generation with 100% carbon capture and sequestration, or other
undeveloped or commercially unproven technology.
Ultra-Long Duration Storage Assesses the impact of an ultra-long duration electric energy storage
technology (e.g., 100’s of hours) that can be used to integrate wind
and solar. This technology is not commercially available today at
reasonable cost.
Biogas Assesses the impact of a GHG free fuel (e.g., biogas, renewable natural
gas, etc.) that could be used with existing dispatchable generation
capacity.
All three of these alternative technology options have the potential to greatly reduce the required
renewable overbuild of the system as shown in Figure 29. This is achieved because each of these
technologies is dispatchable and can generate energy during prolonged periods of low wind and solar
production when short-duration energy storage would become depleted.
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Figure 29: 2050 100% GHG Reduction Sensitivity Portfolio Results

While these alternative technologies clearly highlight the benefits, there are significant technical
feasibility, economic, and political feasibility hurdles that stand in the way of large-scale adoption of these
alternatives at the present time. In particular, clean baseload would require some technology such as
small modular nuclear reactors which is not yet commercially available. Geothermal could provide a clean
baseload resources but is limited in technical potential across the region. Fossil generation with carbon
capture and sequestration (CCS) is another potential candidate, but the technology is not widely deployed,
the cost at scale is uncertain, and current CCS technologies do not achieve a 100% capture rate. Ultra-long
duration storage (926 hours) is not commercially available at reasonable cost assuming the technology is
limited to battery storage or other commercially proven technologies. Biogas potential is also uncertain
and there will be competition from other sectors in the economy to utilize what may be available. A
detailed table of installed nameplate capacity for each portfolio is summarized in Appendix A.2.
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Table 22 shows key cost metrics for the 100% GHG Reduction sensitivity scenarios. For consistency with
the base case scenarios, all costs are relative to the 2050 Reference scenario.
Table 22. 100% GHG Reduction Sensitivity Key Cost Metrics
Metric
100% GHG Reduction Baseline
100% GHG Reduction Clean Baseload
100% GHG Reduction Ultra-Long Duration Storage
100% GHG Reduction Biogas
Carbon Emissions (MMT CO2 / year) 0 0 0 0
Annual Incremental Cost ($B) $12- $28 $11-$22 $370-$920 $2 - $10
Annual Incremental Cost ($/MWh) $39-$91 $36-$70 $1,200-$3,000 $5 - $32
Analyzing the portfolio and key cost metrics for each of the 100% GHG Reduction sensitivity cases yields
several notable observations.
 In the Clean Baseload sensitivity, the availability of a carbon-free source of baseload generation
dramatically reduces the amount of investment in variable renewables and storage needed to
maintain reliability: adding 11 GW of clean baseload resource displaces a portfolio of 15 GW solar,
37 GW wind, and 11 GW of storage. In the context of a highly renewable grid, baseload resources
that produce energy round-the-clock—including during periods when variable resources are not
available—provide significant reliability value to the system. However, at an assumed price of
$91/MWh, the scenario still results in considerable additional costs to ratepayers of between $11-
22 billion per year relative to the Reference Scenario.
 The Ultra-Long Duration Storage sensitivity illustrates a stark direct relationship between the
magnitude of renewable overbuild and the storage capability of the system: limiting renewable
curtailment while simultaneously serving load with zero carbon generation reliability requires
energy storage capability of a duration far beyond today’s commercial applications (this
relationship is further explored in Figure 30 below). Without significant breakthrough in storage
technologies, such a portfolio is beyond both technical and economic limits of feasibility.
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Figure 30: Tradeoff between Renewable Curtailment and Storage Duration

 The Biogas sensitivity demonstrates the relatively high value of the potential option to combust
renewable natural gas in existing gas infrastructure. In this scenario, 14 GW of existing and new
gas generation capacity is retained by 2050, serving as a reliability backstop for the system during
periods of prolonged low renewable output by burning renewable gas. This sensitivity offers the
lowest apparent cost pathway to a zero-carbon electric system because biogas generation does
not require significant additional capital investments. While the biogas fuel is assumed to be quite
expensive on a unit cost basis, the system doesn’t require very much fuel, so the total cost remains
reasonable. Moreover, biogas generation uses the same natural gas delivery and generation
infrastructure as the Reference Case, significantly reducing the capital investments required.
However, the availability of sufficient biomass feedstock to meet the full needs of the electric
sector remains an uncertainty. Moreover, there may be competing uses for biogas in the building
and industrial sectors that inhibit the viability of this approach.

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6 Discussion & Implications
6.1 Land Use Implications of High Renewable Scenarios
Renewables such as wind and solar generation require much greater land area to generate equivalent
energy compared to generation sources such as natural gas and nuclear. In the deep decarbonization
scenarios, significant amount of land area is required for renewable development. In the 100% GHG
Reduction Scenario, estimates of total land use vary from 3 million acres to 14 million acres which is
equivalent to 20 to 100 times the land area of Portland and Seattle combined. This is almost three times
the land use required under the 80% GHG Reduction scenario.
Table 23. Renewable Land Use in 2050
2050 Scenario Units Solar Total Land Use Wind – Direct Land19 Use Wind – Total Land20 Use
80% GHG Reduction Thousand acres 84 94 1,135 – 5,337
100% GHG Reduction Thousand acres 361 241 2,913 – 13,701
Even though such vast expanses of land are available, achieving very high levels of decarbonization would
require extensive land usage for such large renewable development. Additionally, significant quantities of
land would be required to site the necessary transmission to deliver the renewable energy.
19 Direct land use is defined as disturbed land due to physical infrastructure development and includes wind turbine pads, access roads, substations
and other infrastructure
20 Total land use is defined as the project footprint as a whole and is the more commonly cited land-use metric associated with wind plants. They vary
with project and hence as presented as a range
Both direct and total land use for wind is sourced from NREL’s technical report: https://www.nrel.gov/docs/fy09osti/45834.pdf
Land use for solar is sourced from NREL’s technical report: https://www.nrel.gov/docs/fy13osti/56290.pdf
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Figure 31 highlights the scale of renewable development that would be required to achieve 100% GHG
reductions via only wind, solar, and storage. Each dot in the map represents a 200 MW wind or solar farm.
Note that sites are not to scale or indicative of site location.
Figure 31: Map of Renewable Land Use Today and in 80% and 100% GHG Reduction Scenario. Each dot
represents one 200 MW power plant (blue = wind, yellow = solar)

6.2 Reliability Standards
Determining the reliability standard to which each electricity system plans its resource adequacy is the
task of each individual Balancing Authority as there is no mandatory or voluntary national standard. There
are several generally accepted standards used in resource adequacy across North America, with the most
common being the “1-in-10” standard. There is, however, a range of significant interpretations for this
metric. Some interpret it as one loss-of-load day every ten years. Some interpret it as one loss-of-load
event every ten years. And some interpret it as one loss-of-load hour every ten years. The translation of
these interpretations into measurable reliability metrics further compounds inconsistency across
jurisdictions. However, the ultimate interpretation of most jurisdictions ultimately boils down to the use
of one of four reliability metrics:
Today 80% CO2 Reduction 100% CO2 Reduction
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 Annual Loss of Load Probability (aLOLP)
• The probability in a year that load + reserves exceed generation at any time
 Loss of Load Frequency (LOLF)
• The total number of events in a year where load + reserves exceed generation
 Loss of Load Expectation (LOLE)
• The total number of hours in a year where load + reserves exceed generation
 Expected Unserved Energy (EUE)
• The total quantity of unserved energy in a year when load + reserves exceed generation

Each of these metrics provides unique insight into the reliability of the electric system and provides
information that cannot be ascertained by simply using the other metrics. At the same time, each of the
metrics is blind to many of the factors that are ascertained through the other metrics.
The NWPCC sets reliability standards for the Pacific Northwest to have an annual loss of load probability
(aLOLP) to be below 5%. This would mean loss-of-load events occur, on average, less than once in 20
years. However, this metric does not provide any information on the number of events, duration of
events, or magnitude of events that occur during years that experience loss of load. While this metric has
generally served the region well when considering that the biggest reliability drive (hydro) was on an
annual cycle, this metric becomes increasingly precarious when measuring a system that is more and more
dependent upon renewables.
This study uses loss of load expectation (LOLE), because it is a more common metric that is used by utilities
and jurisdictions across the country. Unlike aLOLP, LOLE does yield insight on the duration of events which
can help to provide greater detail whether or not a system is adequately reliable.
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However, LOLE does not capture the magnitude of events when they occur and thus misses a potentially
large measure of reliability as compared to a metric such as EUE. EUE captures the total quantity of energy
that is expected to go unserved each year. While this metric is not perfect, it is likely the most robust
metric in terms of measuring the true reliability of an electric system, particularly in a system that is
energy-constrained. Despite these attributes, EUE is not commonly used as a reliability metric in the
industry today.
RECAP calculates all the aforementioned reliability metrics and can be used to compare and contrast their
performance across different portfolios. Table 24 shows the four reliability metrics across different 2050
decarbonization scenarios.
Table 24: Reliability Statistics Across 2050 Decarbonization Portfolios
Reliability Metric Units
2050
Reference
80%
GHG Red.
100%
GHG Red.
aLOLP %/yr 3.6% 8.1% 10.5%
LOLF #/yr 0.16 0.29 0.13
LOLE hrs/yr 2.4 2.4 2.4
EUE GWh/yr 1.0 2.0 19.0

Because the portfolios were calibrated to meet a 2.4 hrs./yr. LOLE standard, all portfolios yield exactly this
result. However, this does not mean that all portfolios are equally reliable. Notably, the 100% GHG
Reduction scenario has nearly 20 times the quantity of expected unserved energy (EUE) as compared to
the reference scenario. The value of unserved energy varies widely depending on the customer type and
outage duration; studies typically put the value between $5,000 and $50,000/MWh. This means that the
economic cost of unserved energy in the 2050 Reference Scenario is between $5 million and $50 million
per year. However, in the 100% GHG Reduction Scenario, which meets the same target for LOLE, the value
of unserved energy could be nearly $1 billion annually.
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This gives an important insight to some of the qualities of a system that is highly dependent upon dispatch-
limited resources. For a traditional system that is composed mainly of dispatchable generation (coal,
natural gas, nuclear, etc.), the primary reliability challenge is whether there is enough capacity to serve
peak load. Even if the peak is slightly higher than expected or power plants experience forced outages and
are unavailable to serve load, the difference between available generation and total load should be
relatively small. Conversely, for a system that is highly dependent upon variable generation and other
dispatch limited generation, there is a much greater chance that the sum of total generation could be
significantly lower than total load. This phenomenon was highlighted in Section 5.3.3. The reliability
statistics above confirm this intuition by highlighting how aLOLP, LOLF, and LOLE are each uniquely
inadequate to fully capture the reliability of a system that is highly dependent upon variable renewable
energy. For a system that is heavily dependent on variable generation, EUE may be a more useful
reliability metric than the conventional LOLE metrics.
6.3 Benefits of Reserve Sharing
One of the simplifying assumptions made in this study to examine reliability across the Greater Northwest
is the existence of a fully coordinated planning and operating regime within the region. In reality, however,
responsibility for maintaining reliability within the system is distributed among individual utilities and
balancing authorities with oversight from state utility commissions. The current distributed approach to
reliability planning has two interrelated shortcomings:
1) Because the region’s utilities each plan to meet their own needs, they may not rigorously account
for the natural load and resource diversity that exists across the footprint. If each utility built
physical resources to meet its own need, the quantity of resources in the region would greatly
exceed what would be needed to meet industry standards for loss-of-load.
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2) As an informal mechanism for taking advantage of the load and resource diversity that exists in
the region, many utilities rely on front-office transactions (FOTs) or market purchases instead of
physical resources, as was discussed in Section 2. This helps to reduce costs to ratepayers of
maintaining reliability by avoiding the construction of capacity resources. However, as the region
transitions from a period of capacity surplus to one of capacity deficit, and because there is no
uniform standard for capacity accreditation, there is a risk that overreliance on FOTs could lead
to underinvestment in resources needed to meet reliability standards.
Formal regional planning reserve sharing could offer multiple benefits in the Greater Northwest by taking
advantage of load and resource diversity that exists across the region. A system in which each utility builds
physical assets to meet its own needs could result in overcapacity, because not every system peaks at the
same time. Planning to meet regional coincident peak loads requires less capacity than meeting each
individual utility’s peak loads. Further, surplus resources in one area could be utilized to meet a deficit in
a neighboring area. Larger systems require lower reserve margins because they are less vulnerable to
individual, large contingencies. A regional entity could adopt more sophisticated practices and computer
models than individual utilities and manage capacity obligation requirements independent from the
utilities.
Table 25 provides a high-level estimate of the benefits that could accrue if the Northwest employed a
formal planning reserve sharing system. The benefits are divided into (1) benefits due to switching from
individual utility peak to regional peak and (2) benefits due to lower target PRM.
A regional planning reserve sharing system could be established in the Greater Northwest. A regional
entity could be created as a voluntary organization of utilities and states/provinces. The regional entity
would perform loss-of-load studies for the region and calculate the regional PRM and develop accurate
methods for estimating capacity credit of hydro and renewables. The entity would create a forward
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capacity procurement obligation based on studies and allocate responsibility based on their share of the
regional requirement.
Table 25. Possible Benefits from a Regional Planning Reserve Sharing System in the Northwest21
Capacity Requirement BPA + Area NWPP (US)
Individual Utility Peak + 15% PRM (MW) 33,574 46,398
Regional Peak + 15% PRM (MW) 32,833 42,896
Reduction (MW) 741 3,502
Savings ($MM/year) $89 $420
BPA + Area NWPP (US)
Regional Peak + 12% PRM (MW) 31,977 41,777
Reduction (MW) 1,597 4,621
Savings ($MM/year) $192 $555
Rules similar to other markets could be made for standardized capacity accreditation of individual
resources such as dispatchable generation, hydro generation, variable generation, demand response and
energy storage. Tradable capacity products could be defined based on the accredited capacity.
A regional entity could be formed by voluntary association in the Greater Northwest. It could be governed
by independent or stakeholder board. Alternatively, new functionality could be added to the existing
reserve sharing groups such as Northwest Power Pool (NWPP) and Southwest Reserve Sharing Group,
which expand their operating reserve sharing to include planning reserve sharing. It would not require
setting up a regional system operator immediately and PRM sharing could be folded into a regional system
operator if and when it forms.
21 Calculated regional and non-coincident peaks using WECC hourly load data averaged over 2006-2012. Savings value estimated using capacity cost
of $120/kW-yr. Assumes no transmission constraints within the region. Ignores savings already being achieved through bilateral contracts
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7 Conclusions
The Pacific Northwest is expected to undergo significant changes to its electricity generation resource mix
over the next 30 years due to changing economics of resources and more stringent environmental policy
goals. In particular, the costs of wind, solar, and battery storage have experienced significant declines in
recent years, a trend that is expected to continue. Greenhouse gas and other environmental policy goals
combined with changing economics have put pressure on existing coal resources, and many coal power
plants have announced plans to retire within the next decade.
As utilities become more reliant on intermittent renewable energy resources (wind and solar) and energy-
limited resources (hydro and battery storage) and less reliant on dispatchable firm resources (coal),
questions arise about how the region will serve future load reliably. In particular, policymakers across the
region are considering many different policies – such as carbon taxes, carbon caps, renewable portfolio
standards, limitations on new fossil fuel infrastructure, and others – to reduce greenhouse gas emissions
in the electricity sector and across the broader economy. The environmental, cost, and reliability
implications of these various policy proposals will inform electricity sector planning and policymaking in
the Pacific Northwest.
This study finds that deep decarbonization of the Northwest grid is feasible without sacrificing reliable
electric load service. But this study also finds that, absent technological breakthroughs, achieving 100%
GHG reductions using only wind, solar, hydro, and energy storage is both impractical and prohibitively
expensive. Firm capacity – capacity that can be relied upon to produce energy when it is needed the most,
even during the most adverse weather conditions – is an important component of a deeply-decarbonized
grid. Increased regional coordination is also a key to ensuring reliable electric service at reasonable cost
under deep decarbonization.
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7.1 Key Findings
1. It is possible to maintain Resource Adequacy for a deeply decarbonized Northwest electricity grid,
as long as sufficient firm capacity is available during periods of low wind, solar, and hydro
production;
o Natural gas generation is the most economic source of firm capacity today;
o Adding new gas generation capacity is not inconsistent with deep reductions in carbon
emissions because the significant quantities of zero-marginal-cost renewables will ensure
that gas is only used during reliability events;
o Wind, solar, demand response, and short-duration energy storage can contribute but
have important limitations in their ability to meet Northwest Resource Adequacy needs;
o Other potential low-carbon firm capacity solutions include (1) new nuclear generation,
(2) fossil generation with carbon capture and sequestration, (3) ultra-long duration
electricity storage, and (4) replacing conventional natural gas with carbon-neutral gas
such as hydrogen or biogas.
2. It would be extremely costly and impractical to replace all carbon-emitting firm generation
capacity with solar, wind, and storage, due to the very large quantities of these resources that
would be required;
o Firm capacity is needed to meet the new paradigm of reliability planning under deep
decarbonization, in which the electricity system must be designed to withstand prolonged
periods of low renewable production once storage has depleted; renewable overbuild is
the most economic solution to completely replace carbon-emitting resources but requires
a 2x buildout that results in curtailment of almost half of all wind and solar production.
3. The Northwest is expected to need new capacity in the near term in order to maintain an
acceptable level of Resource Adequacy after planned coal retirements.
4. Current planning practices risk underinvestment in the new capacity needed to ensure Resource
Adequacy at acceptable levels;
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o Reliance on market purchases or front-office transactions (FOTs) reduces the cost of
meeting Resource Adequacy needs on a regional basis by taking advantage of load and
resource diversity among utilities in the region;
o Capacity resources are not firm without a firm fuel supply; investment in fuel delivery
infrastructure may be required to ensure Resource Adequacy even under a deep
decarbonization trajectory;
o Because the region lacks a formal mechanism for ensuring adequate physical firm
capacity, there is a risk that reliance on market transactions may result in double-counting
of available surplus generation capacity;
o The region might benefit from and should investigate a formal mechanism to share
planning reserves on a regional basis, which may help ensure sufficient physical firm
capacity and reduce the quantity of capacity required to maintain Resource Adequacy
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Appendix A. Assumption Development
Documentation
A.1 Baseline Resources
Table 26. NW Baseline Resources Installed Nameplate Capacity (MW) by Year.
Category Resource Class 2018 2030 2050
Thermal
Natural Gas 12,181 19,850 31,500
Coal 10,895 8,158 0
Nuclear 1,150 1,150 1,150
Total 24,813 29,745 33,237
Firm Renewable Geothermal 79.6 79.6 79.6
Biomass 489.2 489.2 489.2
Variable Renewables Wind 7,079 7,079 9,205
Solar 1,557 1,557 3,593
Hydro Hydro 35,221 35,221 35,221
Storage Storage 0 0 0
DR Shed Demand Response 600 2,200 5,500
Imports Imports* 3,400 3,400 3,400
*Imports consist of market purchases and non-summer firm imports. For more details, please refer to Imports
section.

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A.2 Portfolios of Different Scenarios

Table 27. Portfolios for 2030 scenarios – Installed Nameplate Capacity (GW) by Scenario
Resource Class Reference No Coal
Solar 1.6 1.6
Wind 7.1 7.1
DR 2.2 2.2
Hydro 35.2 35.2
Coal 8.2 -
Natural Gas 19.9 28.0
Nuclear 1.2 1.2
Bio/Geo 0.6 0.6
Storage - -
Imports 3.4 3.4

Table 28. Portfolios for 2050 scenarios – Installed Nameplate Capacity (GW) by Scenario
Resource Class Reference 60% GHG
Reduction
80% GHG
Reduction
90% GHG
Reduction
98% GHG
Reduction
100% GHG
Reduction
Solar 3.6 10.6 10.6 10.6 29.2 45.6
Wind 9.2 22.9 38.0 48.2 53.8 97.4
DR 5.5 5.5 5.5 5.5 5.5 5.5
Hydro 35.2 35.2 35.2 35.2 35.2 35.2
Coal - - - - - -
Natural Gas 31.5 25.5 23.5 19.5 13.5 -
Nuclear 1.2 1.2 1.2 1.2 1.2 1.2
Bio/Geo 0.6 0.6 0.6 0.6 0.6 0.6
Storage - 2.2
(4-hr)
2.2
(4-hr)
4.4
(4-hr)
6.7
(4-hr)
28.7
(6-hr)
Imports 3.4 3.4 3.4 3.4 3.4 -
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Table 29. Zero Carbon Sensitivity Portfolios in 2050– Installed Nameplate Capacity (GW) by Scenario
Resource Class 100% GHG Reduction
Renewables
100% GHG Reduction
Baseload Tech
100% GHG Reduction
Long Duration Storage
100% GHG Reduction
Biogas
Solar 45.6 30.7 13.5 29.2
Wind 97.4 60.5 49.2 53.8
DR 5.5 5.5 5.5 5.5
Hydro 35.2 35.2 35.2 35.2
Coal - - - -
Natural Gas - - - 13.5
Nuclear 1.2 1.2 1.2 1.2
Bio/Geo 0.6 0.6 0.6 0.6
Storage 28.7
(6-hr)
18.0
(4-hr)
25.9
(926-hr)
6.7
(4-hr)
Clean Baseload - 11.3 - -
Imports - - - -
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Appendix B. RECAP Model
Documentation
B.1 Background
RECAP is a loss-of-load-probability model developed by E3 to examine the reliability of electricity systems
under high penetrations of renewable energy and storage. In this study, RECAP is used to assess reliability
using the loss-of-load expectation (LOLE) metric. LOLE measures the expected number of hours/yr when
load exceeds generation, leading to a loss-of-load event.
LOLE is one of the most commonly used metrics within the industry across North America to measure the
resource adequacy of the electricity system. LOLE represents the reliability over many years and does not
necessarily imply that a system will experience loss-of-load every single year. For example, if an electricity
system is expected to have two 5-hour loss-of-load events over a ten-year period, the system LOLE would
be 1.0 hr./yr LOLE (10 hours of lost load over 10 years).
There is no formalized standard for LOLE sufficiency promulgated by the North American Electric
Reliability Coordinating Council (NERC), and the issue is state-jurisdictional in most places expect in
organized capacity markets. In order to ensure reliability in the electricity system, the Northwest Power
and Conservation Council (NWPCC) set reliability standards for the Pacific Northwest. The current
reliability standard requires the electricity system to have an annual loss of load probability (annual LOLP)
to be below 5%. This would mean loss-of-load events occur, on average, less than once in 20 years.
However, in a system with high renewables, LOLE is a more robust reliability metric.
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B.2 Model Overview
RECAP calculates LOLE by simulating the electric system with a specific set of generating resources and
economic conditions under a wide variety of weather years, renewable generation years, hydro years,
and stochastics forced outages of generation and transmission resources, while accounting for the
correlation and relationships between these. By simulating the system thousands of times under different
combinations of these conditions, RECAP is able to provide a statistically significant estimation of LOLE.
B.2.1 LOAD
E3 modeled hourly load for the northwest under current economic conditions using the weather years
1948-2017 using a neural network model. This process develops a relationship between recent daily load
and the following independent variables:
 Max and min daily temperature (including one and two-day lag)
 Month (+/- 15 calendar days)
 Day-type (weekday/weekend/holiday)
 Day index for economic growth or other linear factor over the recent set of load data
The neural network model establishes a relationship between daily load and the independent variables
by determining a set of coefficients to different nodes in hidden layers which represent intermediate steps
in between the independent variables (temp, calendar, day index) and the dependent variable (load). The
model trains itself through a set of iterations until the coefficients converge. Using the relationship
established by the neural network, the model calculates daily load for all days in the weather record (1948-
2017) under current economic conditions. The final step converts these daily load totals into hourly loads.
To do this, the model searches over the actual recent load data (10 years) to find the day that is closest in
total daily load to the day that needs an hourly profile. The model is constrained to search within identical
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day-type (weekday/weekend/holiday) and +/- 15 calendar days when making the selection. The model
then applies this hourly load profile to the daily load MWh.
This hourly load profile for the weather years 1948-2017 under today’s economic conditions is then scaled
to match the load forecast for future years in which RECAP is calculating reliability. This ‘base’ load profile
only captures the loads that are present on the electricity system today and do not very well capture
systematic changes to the load profile due to increased adoption of electric vehicles, building space and
water heating, industrial electrification. Load modification through demand response is captured through
explicit analysis of this resource in Section 0.
Operating reserves of 1,250 MW are also added onto load in all hours with the assumption being that the
system operator will shed load in order to maintain operating reserves of at least 1,250 MW in order to
prevent the potentially more catastrophic consequences that might result due to an unexpected grid
event coupled with insufficient operating reserves.
B.2.2 DISPATCHABLE GENERATION
Available dispatchable generation is calculated stochastically in RECAP using forced outage rates (FOR)
and mean time to repair (MTTR) for each individual generator. These outages are either partial or full
plant outages based on a distribution of possible outage states developed using NWPCC data. Over many
simulated days, the model will generate outages such that the average generating availability of the plant
will yield a value of (1-FOR).
B.2.3 TRANSMISSION
RECAP is a zonal model that models the northwest system as one zone without any internal transmission
constraints. Imports are assumed to be available as mentioned in Imports Section 4.2.3.
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B.2.4 WIND AND SOLAR PROFILES
Hourly wind and solar profiles were simulated at all wind and solar sites across the northwest. Wind speed
and solar insolation data was obtained from the NREL Western Wind Toolkit22 and the NREL Solar
Prospector Database23, respectively and transformed into hourly production profiles using the NREL
System Advisor Model (SAM). Hourly wind speed data was available from 2007-2012 and hourly solar
insolation data was available from 1998-2014.
A stochastic process was used to match the available renewable profiles with historical weather years
using the observed relationship for years with overlapping data i.e., years with available renewable data.
For each day in the historical load profile (1948-2017), the model stochastically selects a wind profile and
a solar profile using an inverse distance function with the following factors:
 Season (+/- 15 days)
• Probability is 1 inside this range and 0 outside of this range
 Load
• For winter peaking systems like the northwest, high load days tend to have low solar
output
 Previous Day’s Renewable Generation
• High wind or solar days have a higher probability of being followed by a high wind or solar
day, and vice versa. This factor captures the effect of a multi-day low solar or low wind
event that can stress energy-limited systems that are highly dependent on renewable
energy and/or energy storage.
A graphic illustrating this process is shown in Figure 32
22 https://www.nrel.gov/grid/wind-toolkit.html
23 https://nsrdb.nrel.gov/
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Figure 32: Renewable Profile Selection Process

B.2.5 HYDRO DISPATCH
Dispatchable hydro generation is a hybrid resource that is limited by weather (rainfall) but can still be
dispatched for reliability within certain constraints. It is important to differentiate this resource from non-
dispatchable hydro such as many run-of-river systems that produce energy when there is hydro available,
similar to variable wind and solar facilities, especially in a system like northwest which has an abundance
of hydro generation.
To determine hydro availability, the model uses a monthly historical record of hydro production data from
NWPCC’s records from 1929 – 2008. The same data is used to model hydro generation in NWPCC’s
GENESYS model. For every simulated load year, a hydro year is chosen stochastically from the historical
database. The study assumes no significant hydro build in the future and no correlation with temperature,
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000 75,000 80,000 85,000 90,000
Pr
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i
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D
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R
e
n
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a
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e

G
e
n
e
r
a
t
i
o
n

(M
W
h
)
Today's Load (MWh)
❑Each blue dot represents a day in the actual renewable generation sample
❑Size of the blue dot represents the probability that the model chooses that day
based on the probability function
Day for which the model is trying to
predict renewable
generation
abs[loadAug 12 –loadi]/stderrload +

abs[renewAug 12 –renewi]/stderrrenew

Probability Function Choices
Inverse distanceSquare inverse distanceGaussian distance
Multivariate normal
Probability of sample i
being selected =Where distancei =
Pr
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s

D
a
y
’
s

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y

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(M
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Daily Load (MWh)
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
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load or renewable generation. Once the hydro year is selected, the monthly hydro budgets denote the
amount of energy generated from hydro resources in that month. Since RECAP optimizes the hydro
dispatch to minimize loss-of-load, providing only monthly budgets can dispatch hydro extremely flexibly.
For example, some of the hydro can be held back to be dispatched during generator outages. Such high
flexibility in hydro dispatch is not representative of the current northwest hydro system. Therefore, the
monthly budget is further divided into weekly budgets to ensure hydro dispatch is in line with operating
practices in the northwest.
In addition to hydro budgets, hydro dispatch has other upstream and downstream hydrological and
physical constraints that are modeled in a hydrological model by NWPCC. RECAP does not model the
complete hydrological flow but incorporates all the major constraints such as sustained peaking
(maximum generation and minimum generation) limits. Sustained peaking maximum generation
constraint results in the average hydro dispatch over a fixed duration to be under the limit. Similarly,
minimum generation constraints ensure average dispatch over a fixed duration is above the minimum
generation sustainable limits. Sustainable limits are provided over 1-hour, 2-hour, 4-hour and 10-hour
durations.
The weekly budgets and sustained peaking limits together make the hydro generation within RECAP
representative of the actual practices associated with hydro generation in the northwest. Output from
RECAP are benchmarked against hydro outputs from NWPCC’s GENESYS model.
B.2.6 STORAGE
The model dispatches storage if there is insufficient generating capacity to meet load net of renewables
and hydro. Storage is reserved specifically for reliability events where load exceeds available generation.
It is important to note that storage is not dispatched for economics in RECAP which in many cases is how
storage would be dispatched in the real world. However, it is reasonable to assume that the types of
reliability events that storage is being dispatched for (low wind and solar events), are reasonably
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foreseeable such that the system operator would ensure that storage is charged to the extent possible in
advance of these events. (Further, presumably prices would be high during these types of reliability events
so that the dispatch of storage for economics also would satisfy reliability objectives.)
B.2.7 DEMAND RESPONSE
The model dispatches demand response if there is still insufficient generating capacity to meet load even
after storage. Demand response is the resource of last resort since demand response programs often have
a limitation on the number of times they can be called upon over a set period of time. For this study,
demand response was modeled using a maximum of 10 calls per year, with each call lasting for a maximum
of 4 hours.
B.2.8 LOSS-OF-LOAD
The final step in the model calculates loss-of-load if there is insufficient available dispatchable generation,
renewables, hydro, storage, and demand response to serve load + operating reserves.
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Appendix C. Renewable Profile
Development
The electricity grid in the Greater Northwest consists of significant quantities of existing wind and solar
generation. Significant new renewable build is expected to be built in the future, as explored in this study.
Representing the electricity generation from both existing and future renewable (solar and wind) resources
is fundamental to the analysis in this study. In this appendix section, the process of developing these
renewable profiles for both existing and new renewable resources is elaborated.
C.1 Wind Profiles
C.1.1 SITE SELECTION
Existing wind site locations (latitude and longitude) in the study region are obtained from NWPCC’s
generator database and WECC’s Anchor Data Set. New candidate wind sites are identified based on the
highest average wind speed locations across the Greater Northwest region using data published by NREL24
(see Figure 33).
24 https://maps.nrel.gov/wind-prospector/
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Figure 33: Wind speed data in the northwest (Source: NREL)

While striving to place new candidate wind sites in the windiest locations, the new candidate sites are spread
across each state in a way that they span a large geographical area in order to capture diversity in wind
generation (e.g. the likelihood that the wind will be blowing in one location even when it is not in another).
The new candidate sites used in this study are shown in Figure 34. New sites were aggregated geographically
into three single resources that were used in the study modeling: Northwest, Montana, and Wyoming. For
example, Montana wind in the study is represented as a single profile with new wind turbines installed
proportionally across the various “blue squares” shown in Figure 34.
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Figure 34: New Candidate Solar and Wind Sites

C.1.2 PROFILE SIMULATION
NREL’s Wind Integration National Dataset (WIND) Toolkit25 contains historical hourly wind speed data from
2007-2012 for every 2-km x 2-km grid cell in the continental United States. This data is downloaded for each
selected site location (both existing and new sites).
25 https://www.nrel.gov/grid/wind-toolkit.html
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The amount of electricity generated from a wind turbine is a function of wind speed and turbine
characteristics, such as the turbine hub height (height above the ground), and the turbine power curve (the
mapping of the windspeed to the corresponding power output). Wind speeds increase with height above
the ground. Since all NREL WIND data is reported at 100-meters, the wind profile power law is used to scale
wind speeds to different heights, depending on the height of the turbine being modeled. This relationship is
modeled as:
𝑤 𝑑 𝑝 𝑑 ℎ 𝑔ℎ 𝑥
𝑤 𝑑 𝑝 𝑑 ℎ 𝑔ℎ 𝑦=(ℎ 𝑔ℎ 𝑥
ℎ 𝑔ℎ 𝑦)𝑤 𝑑 𝑠ℎ𝑒𝑎𝑟 𝑐𝑜𝑒𝑓𝑓 𝑐 𝑒 𝑡
A wind shear coefficient of 0.143 is used in this study.
A typical power curve is shown in Figure 35. Turbine power curves define the cut-in speed (minimum
windspeed for power generation), rated speed (minimum wind speed to achieve maximum turbine output),
cut-out speed (maximum wind speed for power generation) and power generation between the cut-in
speed and rated speed.
Figure 35: Typical Wind Turbine Power Curve

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With the advancement of wind turbine technology, hub heights have increased over the years (see Figure
36). For existing wind resources, the hub heights are assumed to be the annual average hub height based
on the install year. For new turbines, hub height is assumed to be 100 meters.
Figure 36: Average turbine nameplate capacity, rotor diameter and hub height for land-based wind
project in the US

For existing turbines, Nordic 1000 54m 1 MW (MT) turbine power curve generates wind profiles that
benchmark well to the historical generation profiles. The validation process of turbine power curve selection
is described in greater detail in Section C.1.3. For new turbines, NREL standard power turbine curves are
used to produce future wind profiles.
The wind generation profiles simulation process can be performed for each 2 km X 2 km grid cell and are
usually limited to maximum power of 8 - 16 MW due to land constraints and the number of turbines that
can fit within that area. However, each wind site that is selected as described in Section C.1.1 (shown in
Figure 34), was modeled as 3 GW of nameplate installed wind capacity and encompasses hundreds of
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adjacent grid cells from the NREL WIND Toolkit database. Note that the actual installed wind capacity varies
by scenario in the study and so these 3 GW profiles were scaled up and down to match the installed capacity
of each specific scenario. The adjacent grid cells are chosen such that they are the closest in geographical
distance from the first wind site location (first grid cell). Representing a single wind site using hundreds of
grid cells represents wind production more accurately and irons out any local production spikes that are
limited to only a few grid cells in the NREL WIND Toolkit database.
C.1.3 VALIDATION
BPA publishes historical wind production data26 in its service territory. This data is used to identify a turbine
power curve that best benchmarks wind energy production from existing projects as simulated using
historical wind speed data. Three turbine power curves were tested – GE 1.5SLE 77m 1.5mW (MG), Nordic
1000 54m 1Mw (MT), and NREL standard. Based on annual capacity factors and hourly generation matching,
Nordic 1000 54m 1Mw (MT) turbine was selected to represent existing wind turbines in the study. These
benchmarking results are illustrated in Figure 37 and Figure 38.
26 https://transmission.bpa.gov/business/operations/wind/
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1042 of 1057
Figure 37: Comparison of Annual Wind Capacity Factors for Benchmarking

Figure 38: Comparison of Hourly Historical Wind Generation to Simulated Wind Generation for January
2012

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1043 of 1057
C.2 Solar Profiles
C.2.1 SITE SELECTION
Existing solar site locations (latitude, longitude) in the study region are obtained from NWPCC’s generator
database and WECC’s Anchor Data Set. To build new candidate solar resources in the future, the best solar
sites in the region are identified based on the highest insolation from the solar maps published by NREL27
(see Figure 39). While striving to place new candidate wind sites in the sunniest locations, the new candidate
sites are spread across each state in a way that they span a large geographical area in order to capture
diversity in solar generation (e.g. the likelihood that the sun will be shining in one location even when it is
not in another). The future solar sites used in this study are shown in Figure 34.

27 https://maps.nrel.gov/nsrdb-viewer/
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1044 of 1057
Figure 39: Solar insolation data in the northwest (Source: NREL)

C.2.2 PROFILE SIMULATION
NREL Solar Prospector Database 28 includes historical hourly solar insolation data: global horizontal
irradiance (GHI), direct normal irradiance (DNI), diffuse horizontal irradiance (DHI), and solar zenith angle
from 1998-2014. This data is downloaded for all each selected site location (both existing and new).
28 https://nsrdb.nrel.gov/
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1045 of 1057
The hourly insolation data is then converted to hourly production profiles using the NREL System Advisor
Model (SAM) simulator. Additional inputs used are tilt, inverter loading ratio and tracking type. All panels
are assumed to have a tilt equal to the latitude of their location. The study assumes an inverter loading ratio
of 1.3 and that all solar systems are assumed to be single-axis tracking. The NREL SAM simulator produces
an hourly time series of generation data that is used to represent the electricity generation from the solar
sites in this study.
Forty sites are aggregated to represent the solar candidate resource used in this study. These sites are evenly
distributed in the four states of Oregon, Washington, Idaho, and Utah as shown in Figure 34.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1046 of 1057
2020 Electric Integrated
Resource Plan
Appendix G – New Resource
Table for Transmission
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1047 of 1057
Resource Capacity YearResourceNoteLocationPORPODStartStopMWTotal
Wind Avista System AVA.SYS AVA.SYS 1/1/2022 Indefinite 100.0
Wind Montana AVAT.NWMT AVA.SYS 1/1/2022 Indefinite 100.0 200.0
Wind Avista System AVA.SYS AVA.SYS 1/1/2023 Indefinite 100.0 100.0
Kettle Falls Kettle Falls, WA AVA.SYS AVA.SYS 1/1/2024 Indefinite 12.0 12.0
Pumped Hydro Mid-C MIDC AVA.SYS 1/1/2026 Indefinite 175.0
Rathdrum Rathdrum, WA AVA.SYS AVA.SYS 1/1/2026 Indefinite 24.0 199.0
Wind Off-System Colstrip/BPA AVA.SYS 1/1/2027 Indefinite 200.0
Post Falls Post Falls AVA.SYS AVA.SYS 1/1/2027 Indefinite 8.0 208.0
Hydro Mid-C MIDC AVA.SYS 1/1/2031 Indefinite 75.0 75.0
Hydro Long Lake AVA.SYS AVA.SYS 1/1/2035 Indefinite 68.0 68.0
Storage TBD AVA.SYS AVA.SYS 1/1/2036 Indefinite 25.0 25.0
Storage TBD AVA.SYS AVA.SYS 1/1/2038 Indefinite 25.0 25.0
Storage TBD AVA.SYS AVA.SYS 1/1/2040 Indefinite 25.0 25.0
Storage TBD AVA.SYS AVA.SYS 1/1/2041 Indefinite 25.0 25.0
Wind TBD AVA.SYS AVA.SYS 1/1/2042 Indefinite 100.0
Storage TBD AVA.SYS AVA.SYS 1/1/2042 Indefinite 25.0 125.0
Wind TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 100.0
Storage TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 100.0
Solar TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 5.0 205.0
Storage TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 75.0
Wind TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 50.0
Solar TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 50.0 175.0
Wind TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 100.0
Storage TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 100.0 200.0
Total 1667.0 1667.0
Appendix G
New Resource Table For Transmission
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1048 of 1057
2020 Electric Integrated
Resource Plan
Appendix H – New Resource
Cost Assumptions
Please see Appendix H spreadsheet
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1049 of 1057
2020 Electric Integrated
Resource Plan
Appendix I – Black and Veatch
Renewable Resource and
Storage Study
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1050 of 1057
18 James Gall Avista Corporation 1411 E. Mission Ave. Spokane, WA 99202 Subject: 2019 Avista Integrated Resource Plan Renewable Energy Assumptions Dear Mr. Gall: Black & Veatch Corporation (Black & Veatch) is providing this letter to summarize its review of the inputs for renewable energy and energy storage used in the Avista 2019 Integrated Resource Plan (IRP) process.
Background Avista Corporation (Avista) retained Black & Veatch to provide independent third-party services to review assumptions used for renewable energy and energy storage resources in the 2019 IRP process. Black & Veatch reviewed Avista’s supply side resource option inputs workbook, which includes estimates for values such as capital costs, operating costs, performance characteristics, maintenance requirements, emissions, Power Purchase Agreement (PPA) analyses, etc. for both conventional and renewable energy sources. Specifically, Avista asked Black & Veatch to review the workbook assumptions for upfront capital expenditures (CAPEX), operating & maintenance (O&M) costs, performance, and technology improvement curves for solar, wind, and energy storage resource categories. The purpose of the review was for Black & Veatch to opine on the reasonableness and suggest potential changes if necessary. To assist with the analysis, Black & Veatch used internal knowledge from projects with which it is aware in the Northwest, as well as publicly-available information from industry publications.
Supply Side Renewable Energy Resource Categories The list of supply side resources considered for the review are listed in Table 1.
Table 1: Supply Side Renewable Energy Resource Categories
CATEGORY TECHNOLOGY OWNERSHIP NW Wind On System (101.2 MW) Wind PPA NW Wind Off System (101.2 MW) Wind PPA
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1051 of 1057
CATEGORY TECHNOLOGY OWNERSHIP Wind Montana (101.2 MW) Wind PPA Off Shore Wind (100 MW) Wind PPA Solar PV, Fixed Array (5 MW AC) Solar PPA Solar PV, Single Axis Tracking (100 MW AC) Solar PPA Southern NW Solar PV, Single Axis Tracking (100 MW AC) Solar PPA Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) Solar/Storage PPA Distribution Scale 4hr Lithium-Ion Storage Utility Distribution Scale 8hr Lithium-Ion Storage Utility 4hr Lithium-Ion Storage Utility 8hr Lithium-Ion Storage Utility 16hr Lithium-Ion Storage Utility 40hr Lithium-Ion Storage Utility 4 hr Vanadium Flow Battery Storage Utility 4 hr Zinc Bromide Flow Battery Storage Utility
Capex Assumptions The CAPEX assumptions for supply side resources are listed in Table 2. All CAPEX values are 2018 nominal dollars.
Table 2: Supply Side Renewable Energy CAPEX Assumptions
CATEGORY CAPEX* ($/KWACNW Wind On System (101.2 MW) 1,533 NW Wind Off System (101.2 MW) 1,426 Wind Montana (101.2 MW) 1,426 Off Shore Wind (100 MW) 3,500 Solar PV, Fixed Array (5 MW AC) 1,400 Solar PV, Single Axis Tracking (100 MW AC) 1,157 Southern NW Solar PV, Single Axis Tracking (100 MW AC) 1,157
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1052 of 1057
CATEGORY CAPEX* ($/KWACSolar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 1,504 Distribution Scale 4hr Lithium-Ion 1,950 Distribution Scale 8hr Lithium-Ion 3,822 4hr Lithium-Ion 1,438 8hr Lithium-Ion 2,818 16hr Lithium-Ion 5,578 40hr Lithium-Ion 13,858 4 hr Vanadium Flow Battery 1,600 4 hr Zinc Bromide Flow Battery 1,800 * Excludes AFUDC Black & Veatch notes that there has been limited development of offshore wind projects in the United States, so cost estimates are subject to a higher degree of uncertainty. In addition, most energy storage technologies are undergoing significant development and commercialization, for which CAPEX estimates should also be considered with a higher degree of uncertainty. Overall, the CAPEX assumptions appear reasonable.
O&M Assumptions The O&M assumptions for supply side resources are listed in Table 2. All CAPEX values are 2018 nominal dollars.
Table 3: Supply Side Renewable Energy CAPEX Assumptions
CATEGORY
O&M COSTS
($/KW-YR) NW Wind On System (101.2 MW) 35.0 NW Wind Off System (101.2 MW) 35.0 Wind Montana (101.2 MW) 35.0 Off Shore Wind (100 MW) 90.0 Solar PV, Fixed Array (5 MW AC) 10.0 Solar PV, Single Axis Tracking (100 MW AC) 8.0
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1053 of 1057
CATEGORY
O&M COSTS
($/KW-YR) Southern NW Solar PV, Single Axis Tracking (100 MW AC) 8.0 Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 72.0 Distribution Scale 4hr Lithium-Ion 68.3 Distribution Scale 8hr Lithium-Ion 133.8 4hr Lithium-Ion 50.3 8hr Lithium-Ion 98.6 16hr Lithium-Ion 195.2 40hr Lithium-Ion 485.0 4 hr Vanadium Flow Battery 56.0 4 hr Zinc Bromide Flow Battery 63.0 As noted previously, there has been limited development of offshore wind projects or battery energy storage projects in the United States, so O&M estimates are subject to a higher degree of uncertainty. Overall, the O&M assumptions appear reasonable.
Performance Assumptions The capacity factor and round-trip efficiency values (for energy storage only) assumptions for supply side resources are listed in Table 3.
Table 4: Supply Side Renewable Energy Resource Performance Assumptions
CATEGORY
CAPACITY
FACTOR (%)
ROUND-TRIP
EFFICIENCY (%) NW Wind On System (101.2 MW) 37.0 n/a NW Wind Off System (101.2 MW) 37.0 n/a Wind Montana (101.2 MW) 48.0 n/a Off Shore Wind (100 MW) 50.0 n/a Solar PV, Fixed Array (5 MW AC) 25.0 n/a Solar PV, Single Axis Tracking (100 MW AC) 27.0 n/a
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1054 of 1057
CATEGORY
CAPACITY
FACTOR (%)
ROUND-TRIP
EFFICIENCY (%) Southern NW Solar PV, Single Axis Tracking (100 MW AC) 30.0 n/a Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 27.0 n/a Distribution Scale 4hr Lithium-Ion n/a 88 Distribution Scale 8hr Lithium-Ion n/a 88 4hr Lithium-Ion n/a 88 8hr Lithium-Ion n/a 88 16hr Lithium-Ion n/a 88 40hr Lithium-Ion n/a 88 4 hr Vanadium Flow Battery n/a 70 4 hr Zinc Bromide Flow Battery n/a 67 Actual capacity factor results for renewable energy resources are highly site-dependent and depend on factors such as weather patterns and site topography. However, the values used by Avista fall within expected ranges. Overall, the performance assumptions appear reasonable.
Technology Improvement Assumptions The technology improvement assumptions for supply side resources are listed in Table 4. These values refer to the aggregate industry learning curve of improving technology efficiency from experience and Research & Development efforts.
Table 5: Supply Side Renewable Energy Resource Technology Improvement Assumptions
CATEGORY
ANNUAL TECHNOLOGY
IMPROVEMENT (%) NW Wind On System (101.2 MW) 0.3 NW Wind Off System (101.2 MW) 0.3 Wind Montana (101.2 MW) 0.3 Off Shore Wind (100 MW) 0.3 Solar PV, Fixed Array (5 MW AC) 0.3
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1055 of 1057
CATEGORY
ANNUAL TECHNOLOGY
IMPROVEMENT (%) Solar PV, Single Axis Tracking (100 MW AC) 0.3 Southern NW Solar PV, Single Axis Tracking (100 MW AC) 0.3 Solar PV, Single Axis Tracking (100 MW AC plus 50 MW/200 MWh Lithium-ion) 0.3 Distribution Scale 4hr Lithium-Ion 2.1 to 10.6 Distribution Scale 8hr Lithium-Ion 2.3 to 11.4 4hr Lithium-Ion 2.1 to 10.6 8hr Lithium-Ion 2.3 to 11.4 16hr Lithium-Ion 2.6 to 12.3 40hr Lithium-Ion 3.1 to 14.1 4 hr Vanadium Flow Battery 1.0 to 5.0 4 hr Zinc Bromide Flow Battery 1.0 to 8.0 Black & Veatch notes that solar, wind, and energy storage technologies have all experienced technical improvements over the past decade. While the rate of technology improvement is sometimes uneven, the general industry expectation is that renewable energy and energy storage technologies will continue to advance down the learning curve in future years. In general, the energy storage field is in earlier stages of development and commercialization, and is considered to be more likely to experience faster technological improvements compared to more mature technologies such as wind turbines and PV modules. Overall, the technology improvement assumptions appear reasonable.
Conclusions Black & Veatch reviewed the inputs for renewable energy and energy storage used in the Avista 2019 Integrated Resource Plan (IRP) process. The values used for CAPEX, O&M performance, and technology improvement assumptions appear reasonable and within the range expected for similar facilities.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1056 of 1057
2020 Electric Integrated
Resource Plan
Appendix J – Confidential Report
of Portfolio #14
Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 1a, Page 1057 of 1057
Entire Document is CONFIDENTIAL
Avista Utilities Energy Resources Risk Policy
Pages 1 through 35
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 2(R), Page 1 of 1
Avista Utilities
Generation Infrastructure Plan
2020
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 1 of 40
Table of Contents
Executive Summary ..................................................................................................................................... 1
Introduction ................................................................................................................................................ 2
Generation Capital Expenditures ................................................................................................................ 4
Classification of Infrastructure Need by Investment Drivers ................................................................. 5
Overview of Planned Capital Investments 2020 – 2024 ..................................................................... 8
Overview of Planned Maintenance Investments 2020 – 2024......................................................... 35
Summary & Wrap-Up ................................................................................................................................ 38
Table of Figures

Figure 1. Avista’s Typical Generation Mix .................................................................................................................................... 2
Figure 2. Total Planned Capital Expenditures by Investment Driver 2020 – 2024 ....................................................................... 6
Figure 3. Avista Total Capital Expenditures by Investment Driver ............................................................................................... 8
Figure 4. Avista Total Capital Expenditures by Plant ................................................................................................................... 8
Figure 5. Avista Planned Operational Expenditures for Generation During the Next Budget Cycle ........................................... 35
Figure 6. Avista Projected Generation Operational Expenditures: Hydro .................................................................................. 36
Figure 7. Avista Projected Generation Operational Expenditures: Thermal ............................................................................... 36
Figure 8. Avista Projected Masonry/Structural Repairs .............................................................................................................. 37
Table of Tables

Table 1. Avista’s Planned Generation Capital Expenditures 2020-2024 ...................................................................................... 7
Table 2. Mandatory & Compliance Capital Expenditures 2020-2024 ........................................................................................... 9
Table 3. Failed Plant & Operations Capital Expenditures 2020-2024 ........................................................................................ 11
Table 4. Asset Condition Capital Expenditures 2020-2024 ........................................................................................................ 14
Table 5. Performance & Capacity Capital Expenditures 2020-2024 .......................................................................................... 32

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 2 of 40

Throughout its history, Avista has invested in a broad portfolio of generating assets with the primary focus of
providing low cost and reliable energy to benefit Avista’s customers. While that purpose has not changed, the
utility world is experiencing significant changes that impact the demands placed upon these historical assets and
which are well beyond the scope of their original design.

Generating assets have been historically utilized to support the interconnected transmission grid and provide
energy to customers, but are now being increasingly called upon, via federal regulations, to provide frequency
response, voltage support and system reserves. Another factor coming into play is society’s desire to move to a
“green” energy system. This interest has led to public policy in the form of federal and state tax incentives,
grants, and renewable portfolio standards (RPS) which establish targets to reduce or even eliminate carbon
emissions. These policy changes have encouraged the installation of significant amounts of intermittent wind
and solar-based energy resources which have created new demands on the grid and on existing generation
resources. For example, a wind farm can be producing maximum output for a brief time due to high winds, and
the next moment be producing no energy as the winds die down, requiring a controllable resource such as a
conventional hydro or natural gas plant to make up the difference instantaneously. With all of these changes,
traditional generating stations are being called upon to operate in ways they were not originally designed for by
ramping output up or down more frequently and with larger variations, resulting in increasing wear and tear on
the units and the accompanying higher O&M costs and capital investments required to repair or replace
components to keep these existing assets functioning.

The Company is also committed to mitigating environmental impacts and improving the areas in which it
operates, including direct customer benefits such as parks and boat ramps, issues such as fish and wildlife
habitat protection and enhancement, erosion control, water quality, and a variety of license requirements.
Maintaining compliance with all related regulatory, environmental, societal, legal, safety, and health-related
requirements also results in increasing costs over time as these demands continue to change with better science
and societal values.

Operating a utility is a highly complex business requiring a balancing act between many significant factors
including customer service and reliability, the integrity of the interconnected grid, keeping costs low by utilizing
Company resources and those of the energy marketplace, and protecting and enhancing the areas impacted by
Company operations. Avista’s diverse portfolio provides a strong platform for meeting these requirements, but
as briefly described above, times are changing in the utility world. Investment strategies and decisions will need
to continue to evolve to match the demands placed upon these traditional assets in the future energy space.
This report attempts to describe the ways in which Avista’s Generation group is addressing all of the
requirements being placed on them and on their equipment, from upgrades and new technology to repairing
and replacing assets to keep them in service. For specific details about Avista’s generating resources, equipment,
issues, and a glossary of terms, please see the Company’s 2019 Generation Infrastructure Plan.1

1 Available on the Avenue under “Tools & Resources” then “Avista Infrastructure Plans” as “Generation Infrastructure Plan” or in hardcopy by request.
Executive Summary
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 3 of 40

Avista’s electric generating portfolio is a blend of hydro, natural gas, coal, wood-waste biomass, wind
and solar-powered generation. Many of Avista’s generating assets are
more than 50 years old; some are more than 100 years old. While
these assets have been managed and maintained over the years,
Avista must continually make investments in its generating fleet in
order to continue providing customers with safe and reliable electric
service at a reasonable cost, and with service levels that meet or
exceed customer’s expectations for quality and satisfaction, all while
fulfilling safety and regulatory requirements.

In addition to serving customers by providing low cost energy,
generating resources are a critical element in maintaining overall
system reliability. Avista’s generating resources are called upon to
support system voltage, grid frequency, provide reserves, and deliver
other required operating services needed to maintain a stable and
reliable grid for Avista and across the
Western Interconnection.2
Additionally, Avista is planning to
enter the Western Energy Imbalance
Market (EIM) starting in 2022 to take
advantage of the flexibility of these
resources in an organized market to
the benefit of its customers.

The Company’s typical fuel mix for
generation is shown in Figure 1.3 The
Company owns and operates six
hydroelectric generating stations on the Spokane River and
two more on the Clark Fork River. In addition, the Company purchases output from the City of
Spokane’s hydroelectric projects and from some small customer-owned hydro projects. Altogether,
hydroelectricity provides up to about half of Avista’s capacity to meet customer needs.
Avista is also part-owner of two coal-fired units at the Colstrip Power Generation Station in Montana,
capable of providing up to 12% of the Company’s resource requirements. The Company’s thermal
resources also include five natural gas projects, one of which is a combined cycle plant, four of which
2 Voltage is the pressure from the generator that pushes charged electrons (current) across a power line to the load source. Frequency on the grid is the
change in direction in current flow on an alternating current system. Reserves are energy resources set aside in case a generator goes out of service, a
transmission line fails, or other disruptions to supply occur. Generating governors control the speed of individual generators to help them stay at 60 Hertz
and keep the voltage and frequency of the grid in balance.
3 From Avista’s 2020 Electric IRP, page 4-1, https://www.myavista.com/about-us/our-company/integrated-resource-planning
Introduction
Plant
In
Service
Date
Age Type
Post Falls 1906 114 Hydro
Nine Mile 1908 112 Hydro
Little Falls 1910 110 Hydro
Long Lake 1915 105 Hydro
Upper Falls 1922 98 Hydro
Cabinet Gorge 1952 68 Hydro
Noxon Rapids 1959 61 Hydro
Monroe Street 1992 28 Hydro
Kettle Falls 1983 37 Biomass
Colstrip 3 1984 36 Coal
Colstrip 4 1986 34 Coal
Northeast 1978 42 Gas CT
Rathdrum 1995 25 Gas CT
Boulder Park 2002 18 Gas CT
Kettle Falls CT 2003 17 Gas CT
Coyote Springs 2 2003 17 Gas CC
Buck-A-Block 2002 18 Solar
Community Solar 2015 5 Solar
Lind Solar 2018 2 Solar
Palouse Wind 2011 9 Wind
Figure 1. Avista’s Typical Generation Mix
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 4 of 40
are designed to provide peaking capability. In addition, Avista owns a wood
biomass plant in Kettle Falls and purchases natural gas-fired energy from
Rathdrum Power, an independent power producer.

The Company has pursued an expanding portfolio of renewable wind energy
including purchasing from independent power producer Palouse Wind in
Oakesdale, Washington, with a peak generating capacity of 105 megawatts, as well as purchasing 50
average megawatts of wind energy from the Rattlesnake Flat Wind Project near Lind, Washington
beginning in 2020.4 The Company is also actively pursuing solar technology. Since 2002, the Company
has offered customers the opportunity to purchase solar energy using both a Renewable Energy Credit
Program and a Community Solar Program. The Company contracted for the output of a 20 megawatt
solar generation facility in Lind, Washington in 2018.5 Avista also purchases energy from customer-
owned renewable power projects including the Spokane Waste-to-Energy plant and the Spokane
County Digester.6 A notable strength of Avista’s generation portfolio is the ability to fairly easily
integrate intermittent renewable resources such as wind and solar, primarily due to the flexibility of
the Company’s hydro resources. Compared to the national average, Avista’s “green energy”7
production percentage is one of the highest in the nation, at nearly 61% compared to the national
average of 17%,8 and Avista’s hydro generation is a dominant factor in that success.

The Company has a strong focus on producing sustainable, responsible, and environmentally friendly
energy with its diverse range of resources, creating a portfolio flexible enough to meet baseload
requirements, peaking capacity needs and system stability requirements. The Company has added new
generating capacity to meet growing customer loads since the Company was founded and has worked
to cost-effectively maintain and/or increase the capacity of their generating resources to maximize
their efficiency and output. Avista believes that a diversified portfolio is the most cost-effective tool
available to supply reliable energy to customers under a variety of conditions.9 All of this requires a
balancing act: managing consumer needs and preferences, the ability to meet varying load conditions,
complying with system and regulatory requirements, and optimizing cost to customers are among the
many requirements placed on the Company’s generating resources and staff. Avista’s diverse
generation resource portfolio provides the means of achieving this balance while providing significant
benefits: energy for customers, the flexibility required to maintain the integrity of the grid, the ability
to integrate non-traditional, non-baseload resources such as solar or wind, and to provide opportunity
to participate in the wholesale market on behalf of customers.
4 “Rattlesnake Flat Wind Project to provide Renewable Energy to Avista Customers,” Inland Northwest Partners, March 19, 2019,
http://inwp.org/2019/03/20/rattlesnake-flat-wind-project-to-provide-renewable-energy-to-avista-customers/. This project offers up to 144 megawatts of peak
capacity.
5 Becky Kramer, “81,000 solar panels: Washington’s largest solar farm planned near Lind,” The Spokesman Review, April 8, 2018.
http://www.spokesman.com/stories/2018/apr/08/81000-solar-panels-washingtons-largest-solar-farm-/
6 For details about each of Avista’s generating facilities, please see the Company’s 2019 Generation Infrastructure Plan available on the Avenue under
“Tools & Resources” then “Avista Infrastructure Plans” or in hardcopy by request.
7 “Green Energy” does not include coal, nuclear, natural gas, petroleum, or other non-renewable generation sources.
8 U.S. Energy Information Administration, 2019, https://www.eia.gov/tools/faqs/faq.php?id=92&t=4
9 For a really interesting article about the value of generation diversity, please see: “The Value of US Power Supply Diversity,” Global Energy Institute, July
2014, https://www.globalenergyinstitute.org/sites/default/files/USPowerSupplyDiversityStudy.pdf
Hydro Generation 1,029
Kettle Falls Biomass 54
Wind 40
Total Gen. Capability 1,122
% of Total Gen. Capacity 60%
Avista's "Green" Generating
Resources in Megawatts
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 5 of 40

Many factors go into determining which generating assets to add, upgrade, maintain, and utilize in a
utility’s generation portfolio. For example, when natural gas prices are low, new natural gas-fired
plants may be more competitive than other projects, such as upgrading existing hydroelectric units. On
the flip side, depending upon market conditions, the cost of building new generation may be more
expensive than acquiring energy and services in the wholesale energy marketplace. However, this
decision must be balanced with the risk associated with being dependent upon market prices versus
have the “known” costs associated with a utility-owned resource. This dynamic heavily influences the
Company’s decisions related to investing in new generating resources or adding capacity to existing
resources, as well as how to manage and maintain these key assets.

The changing demands on these units as they
have migrated from simply producing energy to
being needed for wholesale electric markets, grid
support, integration of intermittent renewable
resources, and operations that address
stewardship activities have placed additional
performance demands on power plants, resulting
in maintenance requirements beyond traditional
spending patterns and expectations and
impacting investment decisions for power
companies around the world, Avista included.
The new requirements are demanding that these
historical assets be used in ways beyond their
original design, creating the need for additional
maintenance and capital investments to allow
them to remain operational, especially for the
hydro system.10 These needs are reflected in the
upcoming five-year budget. Collectively these
investments help Avista to effectively support grid reliability needs, meet regulatory and other
mandatory obligations, replace equipment that is damaged, provide opportunities in the wholesale
markets, address system performance and capacity issues, replace equipment that has failed, and
renew infrastructure at the end of its useful life based on asset condition.
10 As mentioned, generation units provide critical support to grid stability. Hydropower is considered “the Guardian of the Grid,” as this resource readily
provides energy, capacity, and ancillary services such as voltage and reactive support. It is highly flexible and complimentary to other types of generation
and its quick response to changing conditions makes it invaluable in meeting the ever-changing needs of the interconnected system. For more
information, please see Electric Research Power Institute, “Quantifying the Value of Hydropower in the Electric Grid: Final Report,”
https://www1.eere.energy.gov/wind/pdfs/epri_value_hydropower_electric_grid.pdf. Also: N. Kumar, P. Besuner, Et al., National Renewable Energy
Laboratory, “Power Plant Cycling Costs,” April 2012, https://www.nrel.gov/docs/fy12osti/55433.pdf

Generation Capital Expenditures

Avista’s generation capital and maintenance
programs are experiencing increasing pressures:

• Aged equipment requires increasing investment in maintenance
to maintain reliability.
• Increasing competition for dollars within the Company.
• Pressure to do more with less. Reduced funding which decreases the depth and frequency of routine maintenance and can provoke postponing major maintenance, putting units at risk of failure.
• Decreases in manpower which shrinks the number of people
available to perform work and requires more capability for automated operation (and associated infrastructure).
• Increasing regulatory requirements (primarily federal) prompting
increasing costs.
• Constantly changing technology. Equipment must be upgraded
or replaced when old technology becomes ineffective and/or is
no longer supported. “Old-time” businesses like utilities can be
slow to accept automation and technology.
• Changing requirements due to market pressures, requiring
updates in controls and technologies to allow participation in
these markets (per regulatory requirements).
• Aging workforce threatening the loss of decades of accumulated
knowledge and experience.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 6 of 40
Each year Avista makes investment decisions for its generating facilities with the goals of maximizing
the value of limited funding and other resources while managing competing requirements and aligning
with Company goals and objectives. A variety of projects are proposed for each budget cycle with
varying characteristics. The Generation group utilizes a formalized process known as the Scheduling,
Cost, and Resource Utilization Meeting or “SCRUM” to develop capital project requests. In these
quarterly meetings, generation leaders and stakeholders discuss criticality, risks, costs, mandatory
requirements, resource requirements, alternatives, and options in order to select and prioritize
projects that are within Generation’s allocated budget and that make best use of the funds they are
given. If a project is approved, a more accurate cost and
time estimate is developed, and once a proposed project is
finalized, it is sent to the Capital Planning Group for further
consideration.

The Capital Planning Group (CPG) is a group of Avista
Directors that represent capital intensive areas of the
Company. Committee members are directors from a variety
of business units to add a depth of perspective, though
their role is to consider capital decisions from the
perspective of overall Company operations and strategic
goals as well as spending guidance set by senior
management and approved by the Finance Committee of
the Board of Directors. They develop a final budget that
represents a reasonable balance among competing needs and business units in order to maintain the
performance of Avista’s systems, as well as provide prudent management of the overall enterprise in
the best interest of shareowners and customers.

Investment strategies and decisions will need to continue to evolve in order to match the demands
placed upon these traditional assets in the future energy space. Challenges that the generation
business will face in the next ten years will likely be quite different than what we can imagine today as
different energy storage technologies evolve and new energy producing technologies are added. Thus
investment decisions for these existing assets must not only address the issues we face today, but
anticipate the needs of the future in order for Avista to continue to provide its customers with
competitive energy resources. Approved projects for Generation during the current budget cycle are
discussed below.

Classification of Infrastructure Need by Investment Drivers

As a way to create more clarity around the particular needs being addressed with each capital
investment as well as simplifying the organization and understanding of Avista’s overall project plans,
the Company has organized all capital infrastructure investments by the classification of need or
•Thermal Operations
•Hydro Operations
•Hydro Operations & Management
•Project Maintenance &
Construction
•Project Delivery
•Electrical Engineering
•Controls Engineering
•Civil Engineering
•Mechanical Engineering
•Maximo Team
SCRUM Meeting Participants
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 7 of 40
“Investment Driver.” The investments associated with each investment driver are briefly defined
below.
• Customer Requested – This category is primarily related to connecting new distribution customers
or large transmission-direct customers and is generally not applicable to Generation, as the
Company is responsible for
determining the contents of
its resource portfolio; this is
not driven by customer
requests. If a project is
budgeted in this category for
Generation, it may include
requests by customer groups
for resource enhancements
such as improved fisheries,
new recreational
opportunities, etc. In the
current budget cycle, there
are no Generation projects
planned in this category.

• Mandatory & Compliance – The Company makes many of its business decisions as a direct result of
compliance with laws, regulations and agreements, including projects related to dam safety
upgrades, public safety, air and water quality, equipment essential to legally operating within the
interconnected grid, etc. These expenditures are compelled by regulation or contract and are
largely beyond the control of the Company. During this budget cycle this category includes FERC
required work to stabilize the Long Lake Power Plant and reinforcing or removing the old penstock
at Monroe Street.

• Failed Plant & Operations – At times assets will fail unexpectedly due to damage or an accident or
will wear out earlier than expected, but this category also accounts for equipment that requires
periodic replacement. Generating assets comprise large, massive rotating equipment and support
machinery with different life expectancies and different maintenance needs than traditional
transmission and distribution utility assets. Sudden mechanical failures or electrical insulation
breakdowns are typical expenditures in this category. During this budget cycle a large expenditure
is required to replace a failed transformer at Coyote Springs, described in more detail below.

• Asset Condition – All assets have a functional service life defined by age, obsolescence, and
degradation of the asset. This category provides funding to replace assets or portions of assets as
needed. This may include replacing parts as they wear out or when items can no longer meet their
required purpose, as systems become obsolete and replacement parts are no longer available, if
safety or environmental issues are identified, if equipment must be upgraded to continue to
provide service, or if the condition of an asset is such that it is no longer optimizing its own
performance or customer value. Some parts are so critical to the operation of a plant that they
cannot be allowed to fail. When these items reach an age when they are close to or at the end of
Figure 2. Total Planned Capital Expenditures by
Investment Driver 2020 – 2024

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 8 of 40
their useful life, the Company preventively replaces them to maintain reliability and acceptable
levels of service. Asset Condition is a major spending category for Generation (as shown in Figure
2), as they are managing many assets that are over 100 years old. It is a continuous process to
replace or overhaul old equipment, bring assets up to current codes and standards, and upgrade
items that are no longer performing to necessary levels. The Generation team has 34 asset
condition related projects in the upcoming budget cycle.

• Customer Service Quality & Reliability – This category is set aside for expenses relating to meeting
customer expectations for quality of service as well as increasing the reliability of operating assets.
Typical expenses the Company would see in this category include distribution feeder automation
which allows isolating the sections of a line so customers not directly impacted by a faulted section
can maintain their service. For Generation, investments in this category are considered with a
different filter and primarily include expenditures such as deployment of automation equipment or
monitoring and control systems that allow generating units to respond to changing system
conditions and to help maintain the reliability of the grid and uninterrupted service to customers.

• Performance & Capacity – Programs in this category help ensure that the Company’s assets satisfy
business needs and meet performance standards. This may include upgrading systems and controls
to improve accuracy, enhancing equipment to increase or ensure production levels, and
contractual work on plants co-owned with others that require routine replacement of parts to
maintain service levels. Avista has traditionally invested in cost effective capacity increases within
its existing fleet of generating assets over time. In the past 25 years, more than 100 megawatts of
new and cost-effective capacity and energy has been created through upgrade programs on these
facilities. This category is also heavily impacted by the way generating resources support the
interconnected grid and by Avista’s participation in the regional wholesale energy market. For
example, in order to participate in regional energy markets, utilities must have software and
controls in place to ensure that every transaction is closely monitored and tracked. These types of
expenditures fall under this category.

All Avista’s capital expenditures can be characterized by one of these drivers, though not all the
investment driver categories are represented for each asset class. For example, electric distribution
investments utilize all six categories; however, investments planned for Generation during the
upcoming five-year planning cycle do not include any projects in the category of Customer Requested.
This is not unexpected, as customers do not request that Avista build power plants. Also note that not
all the investment drivers will be used in all Avista’s primary asset categories in every budgeting cycle,
Table 1. Avista’s Planned Generation Capital Expenditures 2020-2024

Business Driver 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Mandatory & Compliance $880,000 $1,605,000 $13,010,000 $11,300,000 $0 $26,795,000 $5,359,000
Failed Plant & Operations $9,371,680 $7,240,000 $4,840,000 $3,600,000 $3,600,000 $28,651,680 $5,730,336
Asset Condition $38,455,125 $43,423,675 $35,803,738 $45,651,000 $55,649,000 $218,982,538 $43,796,508
Customer Service Quality & Reliability $585,000 $585,000 $585,000 $650,000 $650,000 $3,055,000 $611,000
Performance & Capacity $2,160,000 $1,080,000 $250,000 $0 $1,300,000 $4,790,000 $958,000
Total $51,451,805 $53,933,675 $54,488,738 $61,201,000 $61,199,000 $282,274,218 $56,454,844
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 9 of 40
yet they remain an efficient and effective way of categorizing expenditures in a clear and transparent
fashion that promotes better understanding of how the Company makes business decisions.

Also, due to the time horizon over which the Company must budget its infrastructure investments,
there may be changes in the actual projects funded, program budgets, and implementation timing.
Such changes may be due to changes in project scope, changing material or resource costs, or a more
refined estimate based on where the project is in its development planning. External factors such as
new regulatory or legislative requirements also drive changes in the plan and budget. Budgets are
continually evaluated and reevaluated to take these factors into consideration.

Overview of Planned Capital Investments 2020 – 2024

Over the next five-year
planning horizon, Avista
expects to spend about $282
million in capital investments
for its generating facilities,
allocated across the capital
budget investment drivers
described earlier. Major
projects include upgrading the
Long Lake dam to allow it to
meet minimum safety
requirements for stability
during maximum flood
conditions, replacing the
generators, turbines and
governors at the 1906 Post Falls
plant, and changing out all of
the intake gates, station service,
and control systems at Cabinet
Gorge. A general description of
the capital projects under each
business driver is provided
below.
Figure 3. Avista Total Capital Expenditures by Investment Driver

Figure 4. Avista Total Capital Expenditures by Plant

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 10 of 40
Mandatory & Compliance

Avista’s Generation fleet is impacted by a variety of federal,
regional, state, and local regulations and requirements.
Environmental and safety requirements also play a major role in
this spending category, which includes investments driven
typically by compliance with laws, rules, and contract
requirements that are external to the
Company. In 1977, the Federal
Government, through the Federal Energy
Regulatory Commission (FERC), became the main regulatory body related to
hydro generation. FERC is responsible for licensing new projects, relicensing
existing projects when their licenses expire, overseeing existing projects, ensuring dam safety, and
administering environmental compliance.11 Avista has six projects on the Spokane River. Five of these
projects12 operate under a single 50-year FERC license, which plays a major role in any mitigation
activities at the plants. Cabinet Gorge and Noxon Rapids on the Clark Fork River are also regulated by
FERC. In addition, Avista is regulated by state, local, and tribal authorities in some instances. Over the
next five-year budget cycle, Avista has two projects in this investment driver. One requires adding
stability to Long Lake dam. The other stabilizes the old penstock at the Monroe Street project.

Long Lake Stability Enhancement

During a FERC annual inspection, the inspector noticed a seeping joint in
an airshaft and requested that Avista evaluate the stability of the intake
and spillway dams including evaluating all loading conditions the dams
may experience including full-pool (normal) operations, probable
maximum flood, and seismic conditions. The analysis revealed that Long
Lake dam does not meet meet minimum safety requirements for stability
during probable maximum flood, full pool, or post-earthquake loading
conditions. FERC requires mitigation to address these issues. In response,
the Company will add additional anchoring to the bedrock of the dam as
well as concrete mass to the dam structure itself for stabilization.
11 This includes wildlife management programs, fishery management programs, recreational facilities, and water quality.
12 Five of the Spokane River Projects: Long Lake, Nine Mile, Monroe Street, Upper Falls, and Post Falls, operate under a single license; Little Falls is
operated under separate authority from the U.S. Congress and an agreement with the Spokane Tribe (due to the year it was built).
Long Lake Dam erosion
Mandatory & Compliance 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Long Lake Stability Enhancement $880,000 $1,455,000 $12,260,000 $11,300,000 $0 $25,895,000 $5,179,000
Monroe Street Abandoned Penstock Stabilization $0 $150,000 $750,000 $0 $0 $900,000 $180,000
Total $880,000 $1,605,000 $13,010,000 $11,300,000 $0 $26,795,000 $5,359,000
Table 2. Mandatory & Compliance Capital Expenditures 2020-2024

Long Lake Dam cracks
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 11 of 40
Construction began in 2019 and should take approximately two years to complete. This project will
also include changes in spillway configurations to reduce dissolved gasses downstream, improving
water quality for fish habitat.

Monroe Street Abandoned Penstock Stabilization

The Monroe Street Powerhouse was
built in 1890 and has undergone
several modernizations over the last
130 years. During the 1972 project, a
new turbine intake and penstock
arrangement was installed. Though
no clear records exist from that time
period regarding this project, it is
believed that the three original
penstock intakes were plugged with
concrete and sealed. These old
penstocks have deteriorated to the point that they are
leaking groundwater into the powerhouse and underground electrical cable vaults as well as causing
flooding in Huntington Park. A thorough assessment identified these old penstocks as high risk due to
their location below a public park, unknown physical condition, and the increased amount of flooding
that has been observed. There is fear that these old penstocks could collapse due to deterioration
and/or the weight of the heavy equipment that traverses them due to renovations at the park and on
the Monroe Street generating station. The Company will address this safety situation by locating the
old penstocks and stabilizing or removing them. At the same time, a thorough examination of the
condition of the original intake dam will take place to validate that it is also stable and safe, as there is
a concern that the river could be undercutting the original rock and mortar foundation. All issues found
for both the penstocks and the intake will be remedied under this business case.

Failed Plant & Operations

This ongoing category provides for the timely restoration of the Company’s facilities and equipment
due to unexpected damage or failure. Assets fail over time, especially when they are assets of the age
of some of Avista’s generating equipment. This high-value equipment requires maintenance,
replacement of parts that fail or wear out, and installing or replacing critical components in order to
allow for continued functional and reliable operation. Funds in this category ensure that equipment
can be repaired and back online as quickly as possible to continue providing reliable service. In the
upcoming budget period, Generation has three primary projects in this category, described below.

Monroe Street intake when built in 1972
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 12 of 40

Base Load Thermal Program

Baseload resources provide a constant level of generation, usually at a lower cost compared to units
used for peaking. These plants are designed to run at the same output level for long periods of time
year-round except when undergoing maintenance or experiencing a forced outage. They are typically
less expensive to operate than other generators once they are running, but some require expensive or
long startup and ramp down times, which makes them best suited to meet the constant baseload of
electricity need. Because of the changing system demands, these baseload assets are increasingly
being required to operate at more variable outputs. Operating them at variable levels in order to meet
changing load conditions increases the wear on the equipment and can cause challenges in meeting
emission requirements or in maintaining operational limits. The Company’s baseload thermal plants
are the wood biomass facility at Kettle Falls and natural gas-fired Coyote Springs 2 generating station.

In the next budget cycle work in the Baseload Thermal Program includes:

Kettle Falls: Replace the furnace grate drive system that moves the burned fuel from the boiler
to the ash disposal system. Exchange the forced draft fan motor that blows the wood waste
into the boiler where it is burned. The diesel fueling system will be improved to provide
additional containment and better onsite fuel handling. The turbine/generator fire system will
also be replaced.
Coyote Springs 2: Replace the system that controls the steam temperature in the boiler,
upgrade the medium pressure steam control valves, upgrade the NOx emissions monitoring
system, and improve site security.

Coyote Springs 2 Single Phase Transformer

Coyote Springs 2 currently uses a three-phase
transformer (GSU) to connect the generator to the
grid. The original transformer and subsequent
three phase replacements have experienced seven
failures between the installation of the first GSU in
2002 and when it suffered a final, catastrophic
failure in 2018. The site spare transformer was
placed in service at that time, but it is experiencing
increasing levels of combustible gases and has been subsequently limited to 90% capacity. There is no
other spare available if this unit fails. Because of the unique voltage connections and capacity
Coyote Springs 2 spare transformer being moved into place
Table 3. Failed Plant & Operations Capital Expenditures 2020-2024

Failed Plant & Operations 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Base Load Thermal Program $2,042,280 $2,790,000 $2,790,000 $3,100,000 $3,100,000 $13,822,280 $2,764,456
Coyote Springs 2 Single Phase Transformer $7,000,000 $4,000,000 $1,600,000 $0 $0 $12,600,000 $2,520,000
Peaking Generation Business Case $329,400 $450,000 $450,000 $500,000 $500,000 $2,229,400 $445,880
Total $9,371,680 $7,240,000 $4,840,000 $3,600,000 $3,600,000 $28,651,680 $5,730,336
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 13 of 40
requirements, these types of transformers must be custom ordered, built to individual specifications,
and can take up to 18 months to receive. Should a GSU failure occur, the plant will be out of service
for that time. The average daily cost in lost power for an outage at Coyote Springs is $18,774, meaning
an 18-month outage would cost the Company in the range of $10.2 million in lost generation. After
analyzing this cost and the current risk of failure, it was determined that the Company would purchase
four single-phase transformers that are smaller, easier to transport, and have additional electrical
clearances (which is believed to be one of the issues causing the failures). Three of these four new
units will be connected, with the fourth to provide redundancy in case one of them fails. These new
units will also provide higher capacity, increased safety, and be built with new high efficiency
technology. Though this project will cost approximately $15 million, it should more than pay for itself
in increased reliability and certainty of plant availability, decreased maintenance costs, and a
significant reduction in the risk of losing generation and associated revenues.

Peaking Generation Business Case

As mentioned earlier, the Company has three primary natural gas peaking facilities.13 These plants
must provide rapid start capability to meet changing load conditions. Their reliability allows the
Company to meet these changes, especially during critical load periods. As would be expected, these
plants require regular maintenance and replacement of parts as they wear out and, in addition, are
subject to stringent environmental and regulatory compliance. In order to meet all these obligations,
the Company is embarking on a several projects related to
these peaking units:

Boulder Park: The air emissions system controller
must be replaced. In addition, the air compressors
used to start the engines have worn out and need
to be exchanged.
Northeast Combustion Turbine: The plant’s current
antiquated sewage management system has
environmental and regulatory issues and will be
replaced, and a new sewage holding tank will be
built. The air compressors used to start the turbine
must also be replaced.
Rathdrum: The current fire
extinguishing system needs to be
modernized and the emissions
control and monitoring system
must be updated.

13 The Kettle Falls CT is used for peaking, but it provides only 7.5 megawatts, so is not a primary peaking plant.
Rathdrum turbine inspection
Boulder Park
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 14 of 40
Asset Condition

This is by far the primary investment driver in Generation,
and that is true across the utility industry in general.
According to an Ernst & Young study, “The utilities sector
is at a precipice. By some estimates, 60% of the electric
grid assets will need replacement in this decade. The
timing of these requirements could not be worse: demand
and use are flat, and regulators are
more strongly scrutinizing, or flat
out denying, rate case increases.
Critical utility assets are reaching or
have already exceeded their useful
lives. A robust reliability-centered
maintenance program can delay or
slow corrosion, but at some point,
these assets will fail…basic logistics
means it may take anywhere from
10 to 20 years to replace these aging assets.”14 Avista’s Generation
group is facing these very real issues. Most of Avista’s generation
assets are decades old and provide nearly continuous service, so are
subjected to a great deal of wear and tear. Generation’s Asset
Condition budget includes programs to
address these issues head-on: rebuilds
related to aging or end-of-life assets,
remedying ancillary equipment failure, and
upgrades related to design, safety,
reliability or other regulatory standards.
While still functional, some systems at
Avista’s power plants are so outdated that
they are no longer supported, and
replacement parts are no longer available.
In addition, increasing amounts of technological equipment is being
required by NERC Standards related to the reliability of the electric grid,
making even functioning older equipment unable to meet the
requirements needed today. Additionally, FERC dam inspection safety
requirements continue to evolve posing challenges to assure safety of the structures and safety for the
public. These additional issues put even more pressure on an already constrained budget. Funding
categories in the Asset Condition driver are shown in Table 4 and briefly described in the text below.
14 Ernst & Young, “Power & Utilities: 5 Insights for Executives,” 2013, https://www.ey.com/Publication/vwLUAssets/EY-
Living_on_borrowed_time/$FILE/EY-5-Insights_protect_PU_Utilities-Risk.pdf
Above: Cabinet
Gorge Unit #1
headgate issues

Left: Post Falls
Powerhouse wall
deterioration

Bottom: Nine Mile
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 15 of 40
Baseload Hydro

Avista’s baseload hydro projects are run-of-river plants without the ability to ramp up or down to meet
changing load conditions due to FERC license and state water permit regulations. While limited in their
flexibility to changing loads, they are still required to meet NERC reliability requirements in terms of
frequency response and voltage support. All four: Post Falls, Upper Falls, Monroe Street, and Nine
Mile Falls, are located on the Spokane River. Projects in the Baseload Hydro category are typically small
capital outlays, short in duration, and reactionary to plant operations issues. These are four of Avista’s
oldest power plants, so existing machinery and systems periodically fail and must be replaced to keep
the plants in service. The amount budgeted in this category is based on historical actuals and designed
to be conservative while providing the flexibility in covering these expenses as they come up. Examples
Table 4. Asset Condition Capital Expenditures 2020-2024

Asset Condition 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Base Load Hydro $756,960 $1,034,100 $1,034,100 $1,149,000 $1,149,000 $5,123,160 $1,024,632
Cabinet Gorge Automation $500,000 $0 $0 $0 $0 $500,000 $100,000
Cabinet Gorge Control Room Replacement $0 $0 $0 $160,000 $1,235,000 $1,395,000 $279,000
Cabinet Gorge Gantry Crane Runway Modernization $500,000 $0 $0 $0 $0 $500,000 $100,000
Cabinet Gorge HVAC Replacement $0 $0 $0 $550,000 $0 $550,000 $110,000
Cabinet Gorge Spillgate Replacement $0 $0 $0 $1,000,000 $2,500,000 $3,500,000 $700,000
Cabinet Gorge Station Service $2,800,000 $750,000 $500,000 $0 $0 $4,050,000 $810,000
Cabinet Gorge Stop Log Replacement $0 $1,000,000 $0 $0 $0 $1,000,000 $200,000
Cabinet Gorge Unit 1 Governor Upgrade $0 $0 $0 $560,000 $0 $560,000 $112,000
Cabinet Gorge Unit 2 Field Pole Refurbishment $0 $0 $0 $0 $1,500,000 $1,500,000 $300,000
Cabinet Gorge Unit 3 Protection & Control Upgrade $1,800,000 $750,000 $0 $0 $0 $2,550,000 $510,000
Cabinet Gorge Unit 4 Protection & Control Upgrade $600,000 $2,000,000 $0 $0 $0 $2,600,000 $520,000
Cabinet Gorge Warehouse Replacement $0 $0 $130,000 $2,025,000 $0 $2,155,000 $431,000
Colstrip 3&4 Capital Projects $12,500,000 $9,400,000 $3,034,000 $4,000,000 $8,000,000 $36,934,000 $7,386,800
Generation DC Supplied System Update $840,000 $840,000 $900,000 $840,000 $900,000 $4,320,000 $864,000
Generation Masonry Building Rehabilitation $0 $1,000,000 $1,000,000 $1,000,000 $1,000,000 $4,000,000 $800,000
HMI Control Software $2,230,625 $1,961,875 $1,195,938 $0 $0 $5,388,438 $1,077,688
Kettle Falls Fuel Yard Equipment Replacement $9,000,000 $7,000,000 $2,400,000 $0 $0 $18,400,000 $3,680,000
Little Falls Intake Gate Replacement $0 $300,000 $2,200,000 $2,000,000 $0 $4,500,000 $900,000
Little Falls Plant Upgrade $2,100,000 $0 $0 $0 $0 $2,100,000 $420,000
Little Falls Spillway Flashboard Replacement $0 $0 $0 $0 $1,000,000 $1,000,000 $200,000
Long Lake Plant Upgrade $1,500,000 $4,500,000 $11,500,000 $11,500,000 $11,500,000 $40,500,000 $8,100,000
Long Lake Replace Plant Emergency Generator $0 $75,000 $650,000 $0 $0 $725,000 $145,000
Monroe Street Generator Excitation Replacement $0 $93,000 $650,000 $182,000 $0 $925,000 $185,000
Nine Mile Powerhouse Crane Rehab $0 $0 $0 $750,000 $750,000 $1,500,000 $300,000
Nine Mile Unit 3 Mechanical Overhaul $0 $0 $0 $0 $2,000,000 $2,000,000 $400,000
Nine Mile Units 3 & 4 Control Upgrade $0 $0 $0 $0 $1,000,000 $1,000,000 $200,000
Noxon Rapids Generator Step-Up Bank C Replacement $0 $0 $0 $1,005,000 $2,406,000 $3,411,000 $682,200
Noxon Rapids Spillgate Refurbishment $500,000 $6,430,000 $5,930,000 $5,930,000 $4,759,000 $23,549,000 $4,709,800
Post Falls Redevelopment Program $0 $0 $0 $0 $2,000,000 $2,000,000 $400,000
Post Falls Landing and Crane Pad Development $190,000 $3,110,000 $0 $0 $0 $3,300,000 $660,000
Post Falls North Channel Spillway Rehabilitation $500,000 $0 $1,500,000 $9,500,000 $10,000,000 $21,500,000 $4,300,000
Regulating Hydro $2,137,540 $3,179,700 $3,179,700 $3,500,000 $3,500,000 $15,496,940 $3,099,388
Upper Falls Trash Rake Replacement $0 $0 $0 $0 $450,000 $450,000 $90,000
Total $38,455,125 $43,423,675 $35,803,738 $45,651,000 $55,649,000 $218,982,538 $43,796,508
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 16 of 40
of Baseload Hydro expenditures in the past have included expenses related to replacing failed spillway
gate controls, projects to drain or divert water away from critical structures, installing security
cameras, and safety features such as handrails and boater warning systems.

Cabinet Gorge Automation

Cabinet Gorge was designed to be a baseload plant. Today it is called upon as a primary baseload
generating resource when stream flows are high but also to quickly change output levels in response to
the variability of wind and solar generation, to adjust instantaneously to changing customer loads, and
to provide grid regulating and stability services such as
frequency and voltage fluctuation response. The existing
equipment at the plant was not designed for these
additional responsibilities, leading to times when the
plant has not responded to system frequency events as
needed due to the older equipment. In addition, the age
of the equipment and the extra burdens placed upon it
due to the changing operations has caused an increasing
number of outages and failures. This equipment must be
replaced and upgraded to the technology needed to
provide the service now required of this plant. In order
to deliver adequate unit response, operating flexibility
and system/grid reliability, the Company will install new
speed controllers (governors), automatic voltage control
equipment, primary unit controls, and protective relay
systems. This will require an extended outage, which
provides time to address other issues without further
impacting plant output, such as insulating the generator
housing roof, upgrading the cooling water system, and
adding ancillary equipment such as unit flow meters.

Cabinet Gorge Control Room Replacement

The existing control room at Cabinet is in the center of
the power plant. It has windows that look out to the old
control panels (no longer used) and doubles as the plant’s
conference and break room. It was built over 60 years ago. The Company plans to reconfigure the
existing space to allow for a modern control room with new controls, monitoring equipment,
additional computers, and adequate security measures as well as addressing the human needs for
training, meeting, and breakroom space.
Cabinet Gorge Station Service
Cabinet Unit #1 governor
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 17 of 40
Cabinet Gorge Gantry Crane Runway Modernization

A gantry crane is one of the most critical components in a power plant. It
is built on a giant steel frame with a beam (or beams) across the top to
support the load it carries on a runway (rails) underneath the main
structure. Gantry cranes are especially useful for their mobility, lifting
capacity, and versatility and can easily move extremely heavy equipment
such as large transformers, turbines, or generators safely from place to
place and at various heights. In 2019 the Cabinet Gorge gantry crane was
rehabilitated to increase its lifting capacity from 275 to 340 tons in order
to handle additional needs at the plant. Unfortunately, as shown in the
photo above, the runway was already in desperate need of repair and
cannot handle the additional weight. The concrete supporting the rails
is cracking and failing and the rails themselves must be strengthened.

Cabinet Gorge HVAC Replacement

The current Cabinet Gorge powerhouse
ventilation system is original to the plant,
built in 1952. It must be operated manually
since the original controls failed. It has no
cooling capacity, meaning that summer
temperatures within the plant frequently
exceed 90° F, which will be made worse
when additional power plant unit upgrades
take place over the next few years. During
the upgrades, more transformers and
rectifiers will be added, increasing the heat
level within the powerhouse. This heat can
lead to overheating of powerhouse equipment such as motors and pumps. Air quality is also a pressing
concern, as there is no air filtration system in place. During fire seasons, smoke can be seen in the
operator work areas. Generation’s approach to this issue is careful and measured, starting with a study
to determine what existing equipment can be reconfigured rather than replaced, and where new HVAC
equipment may be necessary based on the new heat source equipment locations. This approach allows
them to maximize the value of a new system and ensure that it provides adequate heating and cooling
into the future, protecting both valuable employees and critical equipment.

Above: Cabinet gantry crane
runway degradation
Below: Gantry Crane and runway
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 18 of 40
Cabinet Gorge Spillgate Replacement

Spillgates control the flow of water over the dam when
the water in the river exceeds the capability of what can
pass through the turbines. Spillgates protect the dam
during high flows or if the plant (or units at the plant) trip
offline. They allow a controlled release of the water
versus overtopping the
dam. The spillgates at
Cabinet are original to
the dam, over 60 years
old. They are missing
rivets, bent, have worn
out seals (some do not
seal at all), and heavy
amounts of corrosion. Though they have been maintained, they have been exposed to significant
water pressure and the resulting decomposition for decades and have degraded to the point that they
must be replaced for the safety of the dam, employees, and the public. Avista plans to replace each of
the eight spillgates with a new welded design that should provide superior fit and operation. The new
gates will allow for the more continuous operation of the gates as required by Cabinet’s role in
ramping to meet load and to integrate renewable resources, and in meeting grid stability and voltage
control requirements.

Cabinet Gorge Station Service

All generating plants require
electricity in order to operate
equipment at the plant such as the
lights, computers, monitoring
equipment, pumps, compressors and
other motors, as well battery
chargers for DC systems. This
electricity is provided by a power
distribution system called station
service, which can draw power from
a generating unit at the plant or from the grid if the entire
plant goes offline (station service can then be used to restart the units). The Cabinet Gorge station
service system was built in 1951 and has been well used as well as being subjected to extremely wet
conditions since that time. As shown in the photo above, when water flows are high and especially
when the plant is spilling, these components are drenched. Plant electricity needs have greatly
increased since the plant was built and the station service designed and installed, and the
accompanying 26-year-old emergency generator has the same issue. The current station service
transformers no longer have the capacity to provide the needed redundancy of the load currently
Above: Corrosion on Cabinet Gorge Spillgate #8
Left: Spillgates are subjected to a lot of different
damaging factors, including river debris (Spillgate #6)
Cabinet’s station service is located behind that spray
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 19 of 40
demanded of Cabinet and are subject to overloading. The current Motor Control Center15 lacks
monitoring and does not provide adequate visibility into how the station service is performing.

These aged components have the potential to trigger load shedding, generator unit trips, and/or plant-
wide forced outages. At the same time, this equipment has a very long manufacturing lead time,
sometimes several months. This means that a simple switchgear or power cable failure could, for
example, create a lengthy and expensive outage at the plant.16 This risk will be mitigated when the
Company updates, upgrades and/or replaces station service components to bring Cabinet’s station
service up to adequate functionality.

Cabinet Gorge Stop Log Replacement

This project is related to the Cabinet Gorge Spillgate Replacement
Program. Stop logs are welded steel beams with a rubber seal at the
bottom, placed on top of each other into premade slots or guides on
the top of the dam to form a wall. These sections are manually placed
with cranes rather than by automated hoist systems. The primary
purpose of stoplogs is to provide a barrier in front of spillgates so the
spillgates can be maintained or replaced. Stop logs are required to control the reservoir while the old
spillgates at Cabinet are removed and the new ones put in place. Without them, it is not possible to
replace the old spillgates. After the spillgates are replaced, the stoplogs will continue to perform
service as a barrier to the reservoir when the spillgates undergo inspection or maintenance.

Cabinet Gorge Unit 1 Governor Upgrade

All the governors at Avista are being or have been upgraded to programmable logic controller (PLC)
that uses an open architecture platform which can
be modified in the future as operations require. The
governor is the main controller of the turbine,
ensuring that the generator spins at the correct
speed. The governor is constantly monitoring the
frequency on the interconnected grid, automatically
sensing increased, decreased, or no load, and
adjusting the speed of the unit to compensate for
human usage and other variabilities. The PLC is a
computer-based system that controls the
automated functions of the governor, making it
easier to manage, control and react quickly to
15 All motors must be controlled, and in a situation that uses many motors like a generating station, it is highly beneficial to monitor and control all of these
motors from one location. That central location is called the Motor Control Center.
16 An outage at Cabinet is estimated to cost between $5,000 and $9,000 per day, depending on which unit is out of service. This is based on historic
market prices.
Cabinet Gorge Unit 1 governor
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 20 of 40
changing system conditions and operating scenarios. Cabinet Gorge Unit 1 is the last of Avista’s hydro
units to be upgraded to this technology.

Cabinet Gorge Unit 2 Field Pole Refurbishment

A generator is comprised of a stator (the stationary part) and a rotor that spins inside the stator to
create electricity. The poles are a part of creating the magnetic field that allows this to happen. The
field poles at Cabinet are original equipment from 1952. The generators
were upgraded in the early 2000s, but the field poles were not changed,
so the current insulating rating of the poles no longer matches the
insulating rating
of the generator
stator. This
results in the
poles
experiencing higher operating temperatures
than their insulating rating, decreasing the
expected life of the generator and putting its
reliability at risk. The Company plans to
refurbish the poles, rewind17 the generator, and
install new monitoring equipment to protect
these valuable assets. Interestingly, this work
was delayed waiting until the plant’s gantry
crane lifting capacity was increased to allow it
to pull the unit, as mentioned in the Cabinet Gorge
Gantry Crane Runway Modernization business case above.

Cabinet Gorge Unit 3 & 4 Protection & Control Upgrade

Two distinct business cases (for units 3 and 4) are combined in this description because they are
intended to accomplish the same thing. As mentioned earlier, Cabinet Gorge was designed for
baseload operation, but is now required to quickly change output levels to accommodate changing
customer loads, variable output of renewable resources, and to provide frequency, voltage support
and other regulating services for the grid. Controls to adjust output and voltage levels are required to
allow the plant to automatically and instantly react as needed. Protective relay systems will also be
added to detect a fault or system disturbance and trip a circuit breaker to protect the generating units.
17 The rotor's outer surface is covered with electromagnets. The stator's inner surface is made up of copper windings. When the rotor turns inside the
stator, the magnetic field created by the electromagnets causes the electrons in the copper windings to move. Their movement generates the electric
current. Thus, the winding is a critical component in producing electricity. These windings are coated with insulation which, over time, degrades and must
be replaced. This replacement work is called performing a “rewind.”
Cabinet Gorge rotor being pulled for maintenance
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 21 of 40

Cabinet Gorge Warehouse Replacement

Cabinet Gorge has one small warehouse, a non-
insulated steel building that was built about 70 years
ago and is a legacy of the original construction
project. There is not adequate space to store
equipment, no restroom, no heating or cooling
systems, and the building does not meet current fire,
electrical and hazardous material codes, among many
issues. This is especially problematic due to the
difficult winters at Cabinet Gorge. The Company sees
safety and weather risks with continuing to store
expensive vehicles, key spare parts, and equipment
outside or inside the powerhouse. There simply is not
adequate space to serve the needs of the plant
personnel today. Avista plans to replace the old
warehouse with a larger building adequate to the plant’s
needs and which meets code specifications, and includes
restrooms, a covered vehicle parking area, and a new
fueling station which complies with environmental
requirements.

Colstrip 3 & 4 Capital Projects

Avista does not operate the Colstrip facility nor does it prepare the annual capital budget plan. The
plant operator, Talen Energy, provides the annual business plan and capital budgets to the owner
group every September for approval. Avista owns
a 15% share in Colstrip Units 3 & 4. The
expenditures Talen presents for the Colstrip
plant are in accordance with the Ownership and
Operation Agreement among all six parties (the
five owners and Talen).18 Typical expenses are
related to environmental, state and federal
regulations, reliability requirements, and general
sustenance of the facility. Avista’s capital portion
of these expenditures vary depending on if it is
an overhaul year or not but overall average
about $7.5 million a year.

18 The other owners are Puget Sound Energy, Northwestern Energy, Portland General Electric and PacifiCorp.
Existing Cabinet Gorge warehouse
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 22 of 40
Generation DC Supplied System Update

The direct current (DC) system or battery system at each
generation plant is used for the protection, control, and
monitoring equipment at the plant. All of the protection relays,
breaker control circuits and monitoring circuits are fed from this
source, which must always be on-line and providing
service. Over time, several additional battery systems
have come into existence for things like station
service, uninterruptible power supply requirements,
governors, communications, and various controls
systems, leading to a great deal of complexity in
managing and maintaining all the different setups.
There are mandatory NERC requirements related to
inspections, maintenance, and testing of all these
battery banks, adding further complexity and risk of non-
compliance due to lack of standardization. In response,
the Company developed a new standardized generation
plant battery scheme that utilizes a single battery system
for each plant, designed to meet all NERC specifications,
as well as provide redundancy and the capability of
managing all the different activities required of the
batteries. The new system also provides technology that
allows continuously monitoring the systems for operations and maintenance purposes. Upkeep and
support will be streamlined by having the same system at each plant with the capability of growing as
needed while maintaining standardized specifications.

Generation Masonry Building Rehabilitation

Many of Avista’s powerhouses were constructed with brick and
grout one hundred years ago or more.19 The brick and mortar are
failing; some buildings have rained bricks onto the ground in
windstorms or during the freeze and thaw each spring, creating a
safety hazard. Most of this risk is faced by employees and
vehicles, but at Post Street, members of the public are also
exposed to the danger. The Company must address this from both
a safety and a building integrity perspective, and, in response,
developed a refurbishment plan to manage this issue long term. Projects are prioritized based on those
with the most potential danger to employees and the public as well as those in the worst physical
19 These include Little Falls powerhouse and gate building, Long Lake Powerhouse, Nine Mile Falls Powerhouse, Post Street, Post Falls Powerhouse and
substation.
Repairs to a brick wall at Nine Mile
Four of the many battery
systems at the Little Falls
Power Plant
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 23 of 40
condition. All of these buildings will be repaired over time to keep them functioning and safe well into
the future.

Human Machine Interface (HMI) Software

Human Machine Interface (HMI) software creates
screens that are used by Avista’s power plant operators
to monitor and control hydroelectric and thermal
generating facility systems. These screens allow an
operator to run the station from a computer in a
control room rather than having to use equipment on
the generating floor. The existing version of HMI
software Avista utilizes, Wonderware,20 reached the
end of its useful life in 2014 when the platform the
Company is using for it, Windows 7, stopped being sold by Microsoft, who
will no longer support it at all after 2020. In fact, Microsoft has advised users that this version of
Windows is at risk for “critical” system compromise and cyber security issues . Avista plans to replace
this system with new control screens that will be developed using a new software platform. These
screens will be customized to each generating facility and will have user-friendly interfaces. The
Company plans to begin this process immediately to ensure a smooth transition to the required new
systems and to prevent potential cyber security risks. This project aligns with Avista’s Safe & Reliable
Infrastructure Technology goals and objectives.

Kettle Falls Fuel Yard Equipment Replacement

The Kettle Falls fuel yard was designed and built 35 years ago and has reached the end of its useful life
according to industry standards. It consists primarily of a truck scale, dumpers that receive the
delivered fuel, conveyors to move the fuel from the dumpers to the fuel yard, and equipment that
chops the wood into the right size for combustion.
Trucking lengths and weights have significantly
changed since the yard was built. It was designed
for 48-foot trailers. Current trucks typically utilize
trailers of up to 53 feet in length, making
maneuvering in the yard very difficult and creating
issues with trucking safety regulations. In fact, the
trucks do not fit adequately into the dumper area
and must unhitch their trailers to deliver their
loads, creating very real safety hazards.21

20 The existing HMI software Avista uses is Wonderware, sold by Schneider Electric and used by utilities with generating assets nationwide. For more
information, see: https://www.wonderware.com/hmi-scada/intouch/?hsCtaTracking=c2282633-e9e0-46ec-bff6-f974859d18c7%7Cfd4e6403-b324-49df-
b431-89ce894b9dbc
21 In 2013 a fatality occurred when a driver was attempting to unhitch his trailer in order to fit into the dumper area.
Example of an HMI screen
Dust created from dumping loads into undersized equipment,
an environmental and air quality concern
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 24 of 40
In addition, these new larger trucks do not fit on the
current scale. The plant has also outgrown its
conveyor, with fuel constantly spilling over the edges,
creating large amounts of dust and clogging the
equipment. The dust that is created with the large
trucks trying to tip their loads into the undersized
dumper system creates environmental compliance
issues. The constant presence of wet wood also
creates a great deal of rusting in the support equipment
and electrical systems, which have been patched but need to be replaced. 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 to keep the system running. The redesigned fuel yard will help
ensure the safety of the people involved in the operation, keep environmental consequences low, and
help ensure continuous reliable operation of the plant.

Little Falls Intake Gate Replacement

The intake gate is where the river water enters the dam so gravity can pull the water through the
penstock and to the turbine. At Little Falls, the intake gates are powered by an AC motor that is served
by a single source. If power is lost, there is no way to close the gates in the event of a plant emergency.
In addition, the concrete around the intake gates is in such disrepair that the gates cannot be
completely sealed without using divers to manually seal them. Both conditions pose a significant safety
and environmental risk, as they could lead to an uncontrolled release of the water from the reservoir.
The Company plans to remedy this situation by updating the gates and their control components
including repairing the concrete, gate slots, guides and sills to allow the gates to properly seal. This
project will ensure safe and dependable gate operation.

Little Falls Plant Upgrade

The existing Little Falls equipment
ranges in age from 60 to more than
100 years old and has reached the
point of being beyond end-of-life and
into the category of obsolete. Little Falls
has experienced an increase in forced
outages over the past six years, increasing
from about 20 hours in 2004 to several
hundred hours per year over the past
several years due to failures on several
different pieces of equipment. Plant
availability is going steadily downhill. The
Company is in the process of upgrading and modernizing all
Above: Little Falls Left: ice build-up at cracks
Wood chip delivery coming into Kettle Falls yard
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 25 of 40
the equipment in this plant, including the generating units, governors, intake gates, bearings, wicket
gates, station service, control and protection systems to get the plant back to full, reliable operation.
The intake gate project discussed above is part of this overall upgrade program.

Little Falls Spillway Flashboard Replacement

Flashboards are lengths of wood that are put at the top of a dam spillway to raise the operating water
level, which increases the head (reservoir level) of the plant, increasing output. Flashboards have an
advantage in that they are relatively inexpensive and can be quickly removed or may wash away, such
as during a flood. Once the flashboards have been released, they are not recoverable and the wood
floats downstream. The boards are placed by employees in barges out in the reservoir (the technique
shown in the picture below). This task typically takes 10 to 14 days, as the three sections are 185, 262,
and 150 feet long. When the boards must be pulled to prevent upstream flooding or when flows
exceed the plant’s capacity (an event which can occur in a very short time period), a long cable is
strung around two sections of flashboards, tied to the winch of a pickup parked on the shore, and
pulled by the winch until the force of the water causes them to collapse into the river, where they are
washed downstream. The third section must be manually removed. Workers in barges must cut them
out or beat on them to knock them out. Obviously, this creates a number of safety issues as well as
being very slow and inefficient.
In addition, the existing
flashboards cannot be installed in
high water conditions due to safety
concerns, reducing the plant’s potential generating capacity during those times. New boards must be
purchased each time the flashboards have to be removed. Besides the flashboard issues, the Company
found a large crack and some other more minor structural issues in one of the piers of the dam that
will be repaired during this same time period.

Above: Little Falls during spill with
flashboards installed
Right: installing the flashboards
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 26 of 40
Long Lake Plant Upgrade

Long Lake is also a very old power plant; some
of its equipment is over 100 years old. Like
Little Falls, the outage rate has continued to
increase over the past six years as aged
equipment has begun to fail. One of the
turbines failed in 2015, and currently the other
turbines are thrusting too much, which is a sign
of significant wear. The 1990-vintage control
system is also rapidly deteriorating. The original generators, rated at 12 megawatts, are
now operating at a maximum output of 22 to 24 megawatts, well above their nameplate rating.
Though modifications were made to help
accommodate this increased generation, the
units were not designed for this output. They are
also operating at their maximum temperature,
which stresses the life cycle of the already over
fifty-year-old windings. Inspections of the
generator show the stator core is “wavy” where
the core lamination steel should be straight,
indicating higher than expected losses 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, again indicating stress on the equipment.

To make matters worse, the old generator step-up transformers are also continually running at high
temperature. But that is not all. When the Company needs to disconnect station service, the ancient
equipment presents the greatest arc-flash potential in the Company and has directly caused injuries.
The safety and reliability issues presented by all of these issues must be addressed. The Company plans
to completely overhaul or replace this old equipment, modernizing the plant and bringing it up to
acceptable safety and reliability standards.

Long Lake Emergency Generator Replacement

Station service provides the electrical service for the power plant. At Long Lake, this service includes an
emergency generator that provides power to systems to protect machinery and personnel in the event
of a complete loss of power at the plant. Installed in the 1980s, this emergency generator serves as a
back-up power source for critical plant systems including providing electricity to governor oil pumps to
Long Lake
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 27 of 40
maintain control of the turbines, sump pumps to protect the
plant from flooding, battery chargers to keep the critical DC
system available, and some egress lighting for personnel to
safely navigate the area. The emergency generator must be
fully synchronized to the station service so it can seamlessly
transfer via a switch. The current switch is so old that parts are
no longer available for it, and it has begun to fail in testing. In
addition, the emergency generator controls are now well over
30 years old and parts are no longer available. This equipment
is well past useful life and will be replaced.

Monroe Street Generator Excitation Replacement

In order to create the magnetic field
required to generate electricity, an exciter is
used. The exciter controls the magnetic field
of the rotor producing a steady voltage, the
amount of which is determined by the speed
and amount of excitation applied to the
rotor. When the turbine spins the rotor
through this field, the generator creates
electricity. The exciter also regulates the
control and protective parts of the
generator. The Monroe Street exciter was
installed in 1990 and has passed the end of
its expected life of 20 years. Spare parts are no longer available, presenting the risk that a failure of this
system would create an outage that could last several months, with resulting financial impact in lost
generation. This issue will be addressed with the installation of a new excitation system.

Nine Mile Powerhouse Crane Rehabilitation

Cranes are an essential part of maintaining a powerplant. They can lift heavy equipment for access to
plant apparatus or to move heavy loads as needed. Nine Mile has two such cranes, installed in 1993.
These cranes were designed for light
duty with 35 tons of lifting capability
and low duty motors rated at a cycle of
five minutes per hour. This rating was
acceptable at the time. However, in
recent years, the cranes, which have
already reached end-of-life, have
experienced several instances of
Current Long Lake emergency generator
One of Nine Mile’s two powerhouse cranes
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 28 of 40
thermal overloading due to a high level of use that has developed over time. They have had to be shut
down several times, stopping work and delaying projects. These cranes, as mentioned earlier, lift and
move heavy equipment in the powerhouse. A failure could be catastrophic in both damages done to
the plant and the potential loss of life should a crane fail. The Company determined that the most cost-
effective solution is to replace the hoists, trolley system, and archaic control systems with modern
reliable systems to keep the cranes functional for meeting operational needs and for the safety of
employees and power plant equipment.

Nine Mile Unit 3 Mechanical Overhaul

Nine Mile Unit 3 was replaced with a new American Hydro unit in 1995. Unfortunately Nine Mile
suffers from serious issues with sediment from Latah Creek22 which have caused the buckets on this
unit to wear and crack. In addition, the downstream
bearings do not support the thrust of the generator
adequately and put all the pressure on the upstream
generator guides, creating incredible stress, rapid
wear and overheating. Eventually this will cause the
unit to fail. To avoid this extreme, the Company is
going to replace the damaged equipment with new
Francis runners and new downstream bearings,
refurbish the wicket gates, and replace the operating
components with modern equipment.

Nine Mile Units 3 & 4 Control Upgrade

These units were installed in the 1990s as mentioned in the business case above and have reached the
end of their projected lives. In order to continue to ensure that these units operate correctly, the
existing controls must be updated to prevent failures
and unplanned outages. The controls include
governors, voltage and primary unit controls, and the
protective relay system. The governor controls are
especially problematic, as the existing controls are not
sized appropriately to handle the load placed upon
them, causing issues when starting up the units or in
adequately controlling voltage, frequency, speed and
plant output. These controls are a key component in
allowing Avista’s hydro generation resources to provide
operating reserves, instantaneous frequency and
22 Latah Creek (also known as Hangman Creek) has been identified by many sources as having extreme amounts of sediment and erosion issues, all of
which pass through the turbines at Nine Mile Falls. https://celp.org/2017/04/20/watersheds-to-watch-wria-56-hangman-latah/
Nine Mile unit replacement in 1995
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 29 of 40
voltage response, and other requirements in serving Avista customers and being part of the
interconnected Western grid.

Noxon Rapids Generator Step-Up Bank C Replacement

In the mid-1970s Washington Water Power installed Noxon Rapids Unit #5 along with a bank of
transformers to support this new unit. This bank is made up of three 45 MVA transformers which
transform the voltage of Unit #5 from 14,400 volts to a transmission voltage level of 230,000 volts. This
transformer bank is a critical component in moving the energy from the generator to the customer.
The bank is nearly 50 years old. The U.S. Department of
Energy states that the standard useful life of a large
step-up transformer is 40 years.23 These transformers
are custom made and take about a year to acquire, so it
is not in the Company’s best interest to let this unit run
to fail and take a generating unit offline for that time
period, as that would entail a loss of approximately $2
million.24 Also of prime consideration is that Unit 5 is
the largest hydro unit in Avista’s portfolio and is used to
meet load demand variability, system reserves, and to
meet the Company’s obligations to the interconnected
Western grid. It is a critical resource; therefore, the Company will be
replacing this end-of-life transformer bank to ensure continued service from this important unit.

Noxon Rapids Spillgate Refurbishment

Spillgates control the water flow over the dam during times when the amount of water in the river
exceeds what can go through the turbines, which typically happens during high flow conditions or if a
unit trips offline. The eight spillgates at
Noxon are over 60 years old, and
corrosion has caused the gates to
deteriorate. The old gates are a rivet
design that is no longer capable of
meeting the current loading
requirements or potential seismic
conditions required by FERC
specifications. The new gates will feature
an updated structural design including
much more durable welded steel gates,
new controls, seals, and operating
23 “Large Transformers and the U.S. Electric Grid,” U.S. Department of Energy, page v,
https://www.energy.gov/sites/prod/files/Large%20Power%20Transformer%20Study%20-%20June%202012_0.pdf
24 The average power value of Noxon Unit 5 is $8,298 per day or $3 million per year, so this figure is conservative.
Noxon Rapids transformer bank
Noxon spillgates in action
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 30 of 40
mechanisms, all of which will help handle the increased operation of the gates in response to
fluctuating power and market conditions and will meet FERC requirements.

Post Falls Redevelopment Program

The Post Falls plant has been operating with the original generators, turbines
and governors since 1906. Its brick powerhouse with riveted steel
superstructure has not changed since 1906 either. While the plant is still
producing electricity, the generating equipment, protective relaying, unit
controls, and many other components of the operating equipment are
mechanically and functionally failing. The turbines are estimated to be 50%
efficient contrasted to modern turbines, which can exceed 90% efficiency. The
existing governors have had patchwork repairs due to lack of replacement parts,
and while they do allow for some unit control, they are ineffective in their
response to system disturbances. Generator voltage controllers, protective relays,
and unit monitoring systems all have a similar story of marginal functionality. The
generating units are exhibiting signs of failure as well; units 4 and 6 have had to be
de-rated due to their deteriorated condition.

In addition, safety issues have evolved over time. For example, workers access
the runner for maintenance via an access port that is so small that one
person can barely squeeze through
(as shown in the photo on the left). Should
a worker get injured inside the turbine, it is
nearly impossible to extract them. The
safety concerns related to this have
become so grave that the runners have not
been maintained in over ten years. In
addition, the 1940s era generator breakers are located right in
the operator control room, creating a significant arc
flash hazard. One of the primary issues is related to
operational constraints. The old controls simply do not
allow the accurate and precise operational changes
that are mandatory in supporting recreation, fishery,
and other FERC license requirements for this plant,
including total dissolved gas concentrations, fish
habitat minimum flow requirements, and operational
safety for the public during spillgate operation.25 To
remedy these issues, the Company is embarking on a
full replacement of the existing Post Falls units with six
25 For more details about these requirements, please see the internal Company website, the Avenue, under “Tools & Resources” then “Avista
Infrastructure Plans” in “Generation Infrastructure Plan.” Available in hardcopy form if requested.
Worker access port for runner maintenance

Top of the dam
Post Falls wall erosion
Broken headgate gear
Inside Unit 6
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 31 of 40
new variable blade turbines, increasing the generating capacity of the facility by 40% capacity, 15%
energy. All other archaic powerhouse equipment will be replaced at the same time, bringing the plant
up to current safety and operational standards.

Post Falls Landing and Crane Pad Development

The property located adjacent to the Post Falls powerplant is being developed by the City of Post Falls
as a recreation area. Avista took this opportunity to work with the City to develop an additional area of
this property to be used for equipment needed for the current construction project at Post Falls as well
as maintenance activities in the future. When Avista is not using their part of the property, it can be
utilized by the public. This solves a couple of problems quite effectively. First, there is not enough room
at Avista’s current plant property for the equipment needed for the major renovation taking place at
the plant. Second, construction currently blocks access to the reservoir for recreational activities.
Finally, the City’s initial park plan was not planned to provide the access Avista needs for vehicles,
construction equipment, barges, and cranes. Avista worked closely with the City of Post Falls to create
a project that benefits both parties. The City purchased the property with an agreement to allow Avista
the access needed, and Avista agreed to help create and build the associated park for public use.

Post Falls North Channel Spillway Rehabilitation

The North Channel spillway at Post Falls is made up of nine spillgates – one large gate and eight smaller
tainter-style radial gates. The North
Channel spillway is the main spillway
utilized26 when the plant reaches flow
capacity through the generators, thus is
critical to plant operations. During the
Post Falls construction discussed above,
all river flows will be diverted through
this spillway for up to two years.
Unfortunately, it is in no condition to
safely manage the expected flows due to
significant overall concrete deterioration,
leaking joints and lift lines, and a large crack in the
supporting concrete for the eight tainter gates, to name
a few of the known issues. The gate lift mechanisms are mechanically failing, and one has already
failed. The Company plans to replace the old gates and repair the concrete structures which support
them, swap out the gate controls and lifts with new safer components, perform extensive concrete
work (including replacing the spillway piers) and replace all of the original embedded components such
as gate slots, guides and sills. This work will ensure that the spillway is robust enough to handle the
extra usage expected during construction and perform safely well into the future.
26 The South Channel spillway is typically only utilized during extremely high flow conditions, such as during spring runoff.
North Channel Spillway at Post Falls with the large gate
above and the radial tainter gates shown on the left

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 32 of 40

Regulating Hydro

Avista’s regulating plants include Cabinet Gorge, Noxon Rapids, Long Lake and Little Falls, totaling
about 950 megawatts of power generation. Regulating hydro plants have reservoir storage capacity,
enabling them to ramp up and down for load following, provide peaking power, integrate variable
resources such as wind and solar, and provide a wide variety of grid services such as spinning reserves,
reserves, load following, energy imbalance
resolution, frequency response, reactive power, and
voltage control. Funding in this category covers
smaller capital expenditures and upgrades needed
to keep these plants operating safely and reliably.
Most of these projects are short term in duration
and don’t rise to the level of a capital project on
their own. They are usually reactionary to
operations issues that arise, such as replacing a
failed monitoring system, repairing decayed
concrete, or exchanging an end-of-life trash rake. Responding to FERC directives can also fall into this
category. During this budget cycle, this spending category includes a FERC requirement for the
Company to add a redundant spill gate hoist system at Long Lake. Since the expenditures that will be
covered in this case are very difficult to predict and it is primarily responsive in nature, the Company
bases this five-year budget on historical spending
patterns.

Upper Falls Trash Rake Replacement

Trash racks are located on the face of the dam
immediately before the water enters the powerhouse
intake. They are designed to prevent any debris which
could damage the equipment from entering the dam.
Trash racks can become so clogged that the water flow
through the turbine is restricted and generation is
reduced. One means of cleaning them is the use of trash
rakes, which are very heavy- duty scrapers. These rakes
scrape debris off the trash racks and remove it so the water
can enter the dam freely. At Upper Falls, the existing trash
rake is undersized for the amount of debris that flows down
the river and up against the dam. This causes it to
occasionally stall in mid-operation, requiring manual
intervention. It is also too small to lift the logs that wash up,
meaning the plant operators must cut up the logs by hand
Above: Upper Falls trash rake
Below: trash rake conveyor system removing the debris

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 33 of 40
to remove them, defeating the very purpose
of the trash rake. It’s location above the
reservoir means the possibility of hydraulic
fluid from the rake leaking into the water,
posing a potential environmental hazard. The
Company plans to replace this existing rake
system with a larger rake able to reach the
full length of the dam’s trash racks and able
to remove large logs as needed. The new
system includes a replacement conveyor
system with improved safety features,
modern controls, and a containment system
for potential fluid leaks.

Performance & Capacity

Avista’s Performance & Capacity investments target the maintenance or improvement of Company
infrastructure based on verified need or analysis, by industry accepted practices, by contractual
obligations, and/or as prescribed by Company policies, procedures, and standards. The goal of
Performance and Capacity programs is to ensure the safe, efficient, reliable and prudent management
of utility assets and operations. A common example is the objective to operate within established
thermal limits for electrical equipment. Other examples include technology projects designed to
increase system reliability and operational flexibility such as metering, communications, control and
technology upgrades or enhancements made to modernize facilities. Four programs are planned in this
category during the upcoming budget cycle, described below.

Cabinet Gorge 15 kV Bus Replacement

The station service equipment at Cabinet is currently located on the deck of the dam. It is going to be
moved inside the powerhouse to protect it from getting soaked during spill (as shown in the photo)
which has resulted in corrosion of the equipment. (This is part of the Cabinet Gorge Station Service
Original Upper Falls trash racks (across the front) and trash rake
(above the trash racks)

Table 5. Performance & Capacity Capital Expenditures 2020-2024

Performance & Capacity 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Cabinet Gorge 15 kV Bus Replacement $0 $0 $0 $0 $1,200,000 $1,200,000 $240,000
Coyote Springs Long Term Service Agreement $2,160,000 $1,080,000 $0 $0 $0 $3,240,000 $648,000
Upper Falls & Monroe Street Permanent Backup Generator $0 $0 $0 $0 $100,000 $100,000 $20,000
Upper Falls Unit Upgrade $0 $0 $250,000 $0 $0 $4,540,000 $908,000
Total $2,160,000 $1,080,000 $250,000 $0 $1,300,000 $9,080,000 $1,816,000
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 34 of 40
business case described previously.)
In order to make room for the station
service equipment, the existing 15 kV
bus must be moved out of the way. It
must be raised five feet to allow the
new station service equipment to be
installed. Over time the existing main
bus has not kept up with the ratings
of the generators and associated
transformers; it is now about 10%
under what it should be. Generation
developed a creative approach to this
situation which minimized the cost and the outage time while at the same time it addresses the need
for more robust equipment. They will build scaffolding over the existing bus and install most of the
new bus using ceiling hangers rather than moving it completely. This shortens the outage from eight
weeks to six days. At the same time, they will upgrade the bus work to match the needs of the plant.
This work will be planned to dovetail with the Station Service business case to ensure that the work is
as smooth and efficient as possible and does not require an additional outage.

Coyote Springs Long Term Service Agreement

The gas turbine and associated components at Coyote
Springs are subjected to extremely high temperatures
and the associated stress on the equipment. This
equipment must be serviced, repaired, or replaced
regularly, requiring major overhauls every 32,000
operating hours in order to remain operable. Avista
has an operating agreement with Portland General
Electric, who operates the plant, and a Long-Term
Service Agreement (LTSA) with General Electric, who
provides the maintenance for the gas turbine. Annual costs
fluctuate based on the number of sustained operating hours of
the plant. Budgeted values are based upon contractual
agreement. The contract was implemented in 2003, then
renegotiated in 2012 and in 2015. Most of the work done
under this category is related to maintenance and upkeep,
upgrading or enhancing controls, and small improvements that
increase efficiency and plant output.

Coyote Springs damage

Overhauling Coyote Springs

Current position of Cabinet station service
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 35 of 40
Upper Falls & Monroe Street Permanent Backup Generator

Upper Falls and Monroe Street Generating Stations provide a large part of downtown Spokane’s power
needs. In order to improve the reliability of this system, a backup generator is needed to ensure that in
the event of an unexpected plant shutdown, critical
elements needed to manage the Spokane River in
the downtown Spokane area can be supplied.
Currently this backup is provided by a shared
generator that is on a trailer and must be towed by
a certified towing operator to one of five possible
connection points, requiring lost time as the trailer
is pulled into place, tested, and connected to the
system. The Company plans to install a permanent
onsite backup generator available to both plants
that will be automatically triggered by the loss of
primary power. The generator will be located close
to a fuel source and will be tested regularly to ensure proper operation when called upon.

Upper Falls Unit Upgrade

Upper Falls, built in 1922, is still utilizing all-original
equipment from that time. It has one of the oldest turbines in
Avista’s fleet and is due for some major overhauls. The runner
is extremely difficult to access, so has experienced very little
maintenance or inspection over the last nearly 100 years. The
runner will be replaced with a new design that should
increase capacity to the unit by
using available water more
efficiently. The generator is still
functional but requires
replacement of the core, a
rewind to replace the ancient
insulation of the generator and
associated field pole, and
replacement of wooden bearings,
the current wearing of which is
causing excessive vibrations. The
wooden turbine guide will also be
replaced, which should also help reduce vibrations. During the
course of this work, the oil lubrication system, operating
components, and other controls for the unit will be
modernized. This work should increase the safe, reliable and
efficient operation of the plant and reduce O&M expenditures currently required to keep the
antiquated systems functioning.
Upper Falls Power Station
Upper Falls components

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 36 of 40
Overview of Generation Planned Maintenance Investments 2020 – 2024

All power plants require various levels of continuous maintenance to ensure their safe, reliable, and
effective operations. This starts with the concept of anticipating system and equipment failures or
breakdowns by servicing these systems and equipment at regular intervals and replacing parts
(hopefully before they fail). The ideal maintenance strategy is about applying the right measures at the
right times. As a general rule, the judicious identification and correct assessment of existing
weaknesses in equipment can
prevent many failures; however, an
effective maintenance strategy
also involves a careful balance of
risk and expense – providing
adequate maintenance while not
spending an excessive amount of
money in doing so. There are
ongoing efforts in the Generation
group to better document
equipment condition and to
develop a balance of risks, costs,
and performance needs of this
equipment as it impacts the
generating assets.

Avista’s maintenance practices include combinations of preventive and corrective measures so that
structures, systems and components perform as intended now and into the future. Some critical
maintenance elements include items that utilities are compelled to complete due to regulatory
requirements. These can include dam safety issues, containment and management of oil or other
releases, air emission controls and monitoring, water quality measures, and FERC license compliance.

Increasing federal regulation to maintain transmission grid stability and reliability related to required
reserves and the penetration of renewable generation have begun to impact plant operations and
O&M costs. According to the National Renewable Energy Laboratory (NREL), the constant cycling to
keep units available in order to follow changes in customer load and to make up for the intermittent
generation of wind and solar is causing damage to equipment and increasing utility operating costs.
Every time a power plant is turned on and off, its components go through large thermal and/or
pressure stresses, resulting in what the Lab calls “creep-fatigue.” 27 Without appropriate maintenance,
this can result in shorter life expectancies of critical components, higher forced outage rates, and
reduced overall plant life. This is true even for power plants that are flexible, such as Avista’s reservoir-
based hydro projects or the Company’s natural gas peaking units. This wear and tear on equipment
27 N. Kumar, P. Besuner, Et al., National Renewable Energy Laboratory, “Power Plant Cycling Costs,” April 2012,
https://www.nrel.gov/docs/fy12osti/55433.pdf
Figure 5. Avista Planned Operational Expenditures for Generation During the Next Budget Cycle

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 37 of 40
ultimately leads to higher maintenance costs, and this can show up even years later in lower capacity
factors, less generation, and higher production costs.28 Lack of investment in maintenance can have
costly consequences. Besides safety risks, defects in power stations can result in loss of production and
can lead to higher cost remediation measures.

Avista, like many utilities across America, is
dealing with increasing and continually
changing performance requirements and the
resulting maintenance demands and costs
related to these changes. In addition, aging
equipment and shrinking O&M budgets are
creating new challenges to overcome. The
Company’s maintenance strategy is a balancing
act that includes many facets: risk of failure,
cost, manpower availability, equipment
availability, customer load levels, stream flows,
market prices, natural gas prices, regulatory
requirements, asset management strategies,
environmental impacts, and other factors.

Over the next five years the Company plans to
spend an average of about one million per year maintaining hydro facilities and about half a million per
year on our thermal plant at Kettle Falls. As shown in Figure 6, a lot of work is needed on the structures
related to the generating station,
including repairing damaged or broken
concrete and cracks, grouting, and
rectifying erosion issues (shown in the
pie chart as “Masonry Repair”). Other
significant expenditures include
repairing the cranes at Noxon and
Cabinet, headgate and draft tube work
at Noxon and penstock work at Little
Falls. All of the plants will undergo
routine maintenance and inspections,
and most will receive new
performance monitoring equipment. A
brief description of the more specific
operations work planned is described below.

28 In fact, studies have shown that 60% to 80% of all power plant failures are related to cycling operations. Study by Intertek-Aptech, Steven A. Lefton and
Douglas Hilleman, “Make Your Plant Ready for Cycling Operations,” Power Magazine, August 2011, http://www.powermag.com/make-your-plant-ready-
for-cycling-operations/?pagenum=1
Figure 7. Avista Projected Generation Operational
Expenditures at Kettle Falls
Figure 6. Avista Projected Generation Operational
Expenditures: Hydro
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 38 of 40
Kettle Falls: Over the next five years the boiler
grate will be rebuilt along with the boiler feed
pump. Unit 2 will undergo major maintenance, and
the plant turbine trip and throttle will be
renovated. The big caterpillar that pushes the wood
waste into place and organizes it needs to be
regularly maintained, which includes replacing the
tracks and rollers periodically. During this budget
cycle a major overhaul will also take place.

Cabinet Gorge: Cabinet will be receiving draft tube gate repairs. In addition, the penstock will
be painted and coated with epoxy, not only to protect the metal from corrosion, but because
this creates a “slicker” surface, increasing the hydrodynamic performance of the plant. The
draft tube gates will be repainted, and the seals will be refurbished, the gantry crane runway
concrete will be repaired, and the stop logs refurbished.
Noxon Rapids: Noxon will undergo painting and maintenance on the headgates, repair of the
draft tube gate seals, and overhaul of its Gantry crane. It requires a lot of masonry work
including repairing an air shaft crack and the face of the dam itself as well as resealing the
powerhouse deck. Work on the gallery drain and sump pump will also take place.
Little Falls: This plant requires some concrete repair on the face of the spillway section of the
dam, on the fish chute, on the barge landing, and on the power plant building. The conduit at
the plant will be moved and repaired and the penstocks will be repainted to protect them from
corrosion and increase their performance.
Long Lake: Long Lake also requires significant repairs to the building masonry as well as
grouting on the spillway piers and the spillway face. Other plans include spillgate, headgate,
and scroll case refurbishment.
Monroe Street: This plant will also
undergo work on the trash racks to
remove rocks and maintenance on
the headgate.
Nine Mile: Powerhouse repair work
is needed at this plant including
repairing the masonry of building
itself and the splitter wall erosion.
Post Falls: This plant also needs
masonry repair and will also
undergo a repair of unit #1.
Post Street: Another plant needing
some significant masonry repair and
new windows. Figure 8. Avista Projected Masonry/Structural Repairs
Kettle Falls Cat
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 39 of 40

Since the early days of the utility business in the late 19th century and throughout the 20th century,
generating plants were constructed to supply utility customers with low cost and reliable energy.
During that time, investment decisions were consistently driven by the need to either maintain or add
enhancements to Company assets in order to continue to provide this low-cost energy. Decisions on
what maintenance was done and what new investments were needed were screened against this low-
cost criterion.
Just as importantly, addressing environmental concerns along with stewardship of the resources
impacted by these generating assets has always been a major consideration and cost driver for the
generation fleet. Hydro generating stations are governed by regulations dictated by the Federal Energy
Regulatory Commission (FERC) which not only determine the way these plants are operated but also
drive significant investments in wildlife, fishery, and recreational programs that benefit the public.
Avista’s plants must also satisfy site permits, water quality monitoring, and disposal permits where
applicable. In addition, historical and cultural resources are actively managed.29 These important
stewardship elements do contribute to the expenses associated with ownership of these assets, but
also help assure that projects are being operated responsibly and that they create public resources
which provide significant benefits to the communities and regions that surround these generating
stations.
Today, the use of Avista’s generating assets is complex and strives to meet multiple demands – those
of grid reliability, low cost energy, wholesale markets, and stewardship as well as manage outside
influences such as costs of natural gas, market effects, commodity pricing, and other factors. All are
key considerations in managing these assets. Consequently, many factors must be balanced with
available funds and resources to achieve acceptable results. Because of this, the process of
determining what work will be done and when it is planned is continually shifting to accommodate any
change in need, purpose, or opportunity that can benefit Avista and its customers. Avista’s generation
infrastructure programs are thoughtfully developed, analyzed, optimized, adjusted, and re-analyzed as
appropriate to ensure that the Company meets all of these requirements.

Over the last 129 years, Avista has built a diverse portfolio of generating assets required to continually
serve the changing needs of customers. Investment strategies and decisions will need to continue to
evolve in order to match the demands placed upon these traditional assets in the future energy space.
Going forward the Generation group will continue to actively manage these resources to provide
reliable and cost-effective service, meet stewardship responsibilities, and provide a stable foundation
as the utility industry transitions to the future.

29 For a great description of FERC’s regulation of hydroelectric power plants, please see “Hydropower Primer: A Handbook of Hydropower Basics,”
Federal Energy Regulatory Commission, https://www.ferc.gov/legal/staff-reports/2017/hydropower-primer.pdf
Summary & Wrap-Up
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 3, Page 40 of 40
Exhibit No. 7, Schedule 4
Capital Investment Business Case Justification Narratives Index
Business Case Name Page Number
Generation and Environmental
Cabinet Gorge Dam Fishway 2
Clark Fork Settlement Agreement 12
Spokane River License Implementation 18
Hydro Safety Minor Blanket 25
Long Lake Stability Enhancement 30
KF_Ash Landfill Expansion 38
Base Load Thermal Program 45
CS2 Single Phase Transformer 53
Nine Mile Rehabilitation 63
Peaking Generation Business Case 67
Base Load Hydro 70
Cabinet Gorge 15 kV Bus Replacement 75
Cabinet Gorge Automation 79
Cabinet Gorge Gantry Crane Replacement 86
Colstrip 3&4 Capital Projects 94
Generation DC Supplied System Update 98
Little Falls Plant Upgrade 105
Long Lake Plant Upgrade 112
Regulating Hydro 123
Cabinet Gorge Unit 3 Protection & Control Upgrade 131
Cabinet Gorge Unit 4 Protection & Control Upgrade 137
Post Falls Landing and Crane Pad Development 143
HMI Control Software 149
Generation Masonry Building Rehabilitation 153
KF_Fuel Yard Equipment Replacement 155
Automation Replacement 164
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 1 of 170
Cabinet Gorge Dam Fishway
Business Case Justification Narrative Page 1 of 10
EXECUTIVE SUMMARY
The Clark Fork Settlement Agreement (CFSA) and FERC License require Avista to
implement the Native Salmonid Restoration Plan (NSRP), which includes a step-wise
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 the 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 $65.8 million will benefit our customers by maintaining compliance
with the CFSA and FERC License and subsequent agreements, which provide operational
flexibility a Aia Nn and Cabine Gge Faciliie.
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
2.0
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 2 of 170
Cabinet Gorge Dam Fishway
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?
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 $65.8M
Requested Spend Time Period 2013 - 2022
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
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 3 of 170
Cabinet Gorge Dam Fishway
Business Case Justification Narrative Page 3 of 10
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
eglain, and USFWS 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
he CFSA, cnien ih he bjecie and e f he 100% deign
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
cce f hi jec ld be Aia cncin f he CGDF, a ecified
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
an bligain Aia ma hae miigae f he Cabine Gge Dam blckage
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
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 4 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 4 of 10
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
Deamen 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 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, $5.9M of planned spend in 2020 has slid into 2021 and an additional
need of funds in 2022 for the construction schedule slide, as well as, 8 additional
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 5 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 5 of 10
months of $2M in AFUDC as the in-service date shifted from September 2021 to
May 2022. This is ultimately resulting in a total cost of capital of $65.8M.
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: $13.6M
- 2021: $16.62M
- 2022: $4.94M
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 fiber 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.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 6 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 6 of 10
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 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, $5.9M of planned spend in 2020 has slid into 2021 and an additional
need of funds in 2022 for the construction schedule slide, as well as, 8 additional
months of $2M in AFUDC as the in-service date shifted from September 2021 to
May 2022.
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

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 7 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 7 of 10
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.

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 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
Guy Paul Senior Engineer II
Andrew Burgess Manager Plant Operations Hydro Cabinet Gorge
Eric Rosentrater Manager Safety, Training Operations & Labor Specialist
Greg Hesler Senior Counsell II
Michele Drake Supervisor Hydro Compliance
Laroy Dowd Chief Operator
Heide Evans Environmental Budget Specialist
Rod Price Manager Real Estate
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)
Matthew Moots (IT/ET) Project Manager
Lindsay Fracas Associate Project Manager
Ryan Traylor Project Engineer
Michael Truex Project Manager
Clint Smith Stantec PM, Engineer of Record
James Larsen CM/Inspector STRATA & All West
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 8 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 8 of 10
Slayden Construction Inc - Contractor

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 ae hen igned f aal b he jec aroval thresholds, and then
processed against the project risk registry, and or contract amendment with the
contractor.

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
7/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 9 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 9 of 10
Title: Sr Dir Environmental Affairs
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 10 of 170
Cabinet Gorge Dam Fishway

Business Case Justification Narrative Page 10 of 10

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 11 of 170
Clark Fork License
Business Case Justification Narrative 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.

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. 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 our 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.

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
1.1
2.0
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 12 of 170
Clark Fork License
Business Case Justification Narrative Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
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
Species Act (fish passage), and state, federal and tribal water quality standards as
applicable. License articles also describe our operational requirements for items such
Requested Spend Amount $5,318,068
Requested Spend Time Period 1 year
Requesting Organization/Department B04/Clark Fork License
Business Case Owner | Sponsor Nate Hall | Bruce Howard
Sponsor Organization/Department A04/Environmental Affairs
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 13 of 170
Clark Fork License
Business Case Justification Narrative Page 3 of 6
as minimum flows, and reservoir levels, as well as dam safety and public safety
requirements.
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.

Option Capital Cost Start Complete
Capital funding $5,318,068 01 2021 12 2021
Activity is mandatory – resulting in operational cost
overage
$0 01 2021 12 2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

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.
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.

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.
NA

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 14 of 170
Clark Fork License
Business Case Justification Narrative Page 4 of 6
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.
spend, and transfers to plant by year.
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.
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.
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
Cabinet Gorge Dam Fishway Project has its own business case and supports meeting
the overall regulatory requirements of the FERC License and CFSA.

3.1 Steering Committee or Advisory Group Information

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,
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 15 of 170
Clark Fork License
Business Case Justification Narrative Page 5 of 6
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
imlemenain aie. Each ea bdge i eablihed inenall a Aia
months prior to the actual capital work plan. In addition, resource conditions,
permitting and other issues impact work plan implementation each year. As a
el, egla ing i eied .

The undersigned acknowledge they have reviewed the Clark Fork License 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
7/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 16 of 170
Clark Fork License
Business Case Justification Narrative Page 6 of 6

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 17 of 170
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 epired in 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 mandator
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 abilit 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.

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

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 18 of 170
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 epired in 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 abilit 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 $1,011,300
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
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 19 of 170
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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 20 of 170
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 $1,011,300 01 2021 12 2021
Activity is mandatory resulting in operational cost
overage
$0 01 2021 12 2021
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
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 21 of 170
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.
Additionall 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 full eplored to ensure Avista s fiduciar dut 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,
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 22 of 170
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.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 23 of 170
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
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 24 of 170
Hydro Safety
Business Case Justification Narrative Page 1 of 5
EXECUTIVE SUMMARY

Through 18 CFR Section 12.42, the Federal Energy Regulatory Commission (FERC) is given
broad regulatory discretion over the installation, operation and maintenance of hydro public safety
deice near Aia dam. In addiion o reglaor reqiremen for ch deice ch a ligh,
sirens, signage and barriers, Avista is subject to potential liability should the company not maintain
safety-related equipment. Projects are identified in a variety of ways, including physical
condition/age/function, changing standards in FERC guidance, industry practice, or emergent
public safety needs. All projects are subject to conceptual approval by the Chief Dam Safety
Engineer and to additional internal review and oversight. Work is both planned and opportunistic,
leveraging scheduled outages. The program cost has historically been approved at $50,000
annually.

This work benefits customers by maintaining and enhancing safety, ensuring compliance, and
reducing risk. Customers impacted include all electric customers in Washington and Idaho
(service code and jurisdiction ED/AN). If this business case is not approved, operating costs would
increase as Avista would still maintain safety-related equipment to remain in compliance. In the
absence of funding, Avista would undertake increased risk by delaying the purchase and
installation of equipment.

VERSION HISTORY
Version Author Description Date Notes
Draft Michele Drake Initial draft of original business case 6/29/2020
1.0 Michele Drake Completed business case 7/27/2020
1.1
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 25 of 170
Hydro Safety
Business Case Justification Narrative Page 2 of 5
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista has an ongoing need to maintain existing hydro public safety measures and to
address any emergent hydro public safety needs.
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 driven by the need to meet overall hydro public safety compliance
requirements and by asset condition. Benefits to the customer include risk and liability
reduction for the company, the presence of measures that improve overall safety for the
recreating public.
Identify why this work is needed now and what risks there are if not
approved or is deferred
Failing to maintain or deferring maintenance of existing hydro public safety measures
or a failure to respond to emerging issues places Avista at risk for liability and non-
compliance penalties. 18 CFR Part 12 delegates the authority to require safety devices
at dams, here necear o he FERC Regional Engineer. Secion 12.42 of he
Reglaion ae ha, To he aifacion of, and ihin a ime pecified b he
Regional Engineer, an applicant or licensee must install, operate, and maintain any
signs, lights, sirens, barriers, or other safety devices that may reasonably be necessary
or desirable to warn the public of fluctuations in flow from the project or otherwise, to
proec he pblic in he e of he projec land and aer. The FERC perform annual
physical inspections of our dams, noting any items that need attention. Measures that
require replacement are also identified by operators and hydro public safety staff.
Requested Spend Amount $50,000
Requested Spend Time Period Annual
Requesting Organization/Department H04 / Hydro Safety
Business Case Owner | Sponsor Michele Drake | Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 26 of 170
Hydro Safety
Business Case Justification Narrative Page 3 of 5
1.3 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 lack of directive hydro public safety related follow-up items from annual FERC
inspections and the timely replacement of equipment are indicators of success.
1.4 Supplemental Information
1.4.1 Please reference and summarize any studies that support the problem
N/A
1.4.2 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
Capital funding $50,000 01 2021 12 2022
Activity continues – O&M budget overage $0 01 2021 12 2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

Funded projects are identified in several ways. During periodic site inspections, FERC
staff may identify a new specific concern or point out an existing item that is deficient
or in need of repair. In other cases, Avista has assessed the condition of safety items at
our dams, and proactively plans replacement or addition of a new safety measure.
Replacement can be driven by physical condition/age/function, changing standards in
FERC guidance, industry practice, or emergent public safety needs. All measures are
subject to the conceptual approval of the Chief Dam Safety Engineer and to additional
internal review and oversight.
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.
Safety items are an on-going process to ensure public safety. Hydro Safety is mandatory
and will result in an O&M expenses if capital dollars are not properly allocated, or in
the worst case, increased risk and liability should projects not be carried out.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 27 of 170
Hydro Safety
Business Case Justification Narrative Page 4 of 5
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 business case involves the hydro public safety business function, impacting the
Dam Safety Team from GPSS and Environmental Affairs. Successful implementation
may include staff work by engineering/design, procurement, plant management,
operations staff and shop crews.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternatives and possible mitigation strategies are considered on a case-by-case basis,
for each proposed measure.
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 timeline depends on the measures targeted for replacement.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Hdro pblic afe effor align ih Aia foc on afe ihin or bine,
reliable energy, and overall 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
N/A
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders, who may interface with the business case, include members of the
Dam Safety Team from GPSS and Environmental Affairs. Customers include
the FERC (regulator) and the recreating public.
2.8.2 Identify any related Business Cases
N/A

3.1 Steering Committee or Advisory Group Information
All projects will be vetted by the Chief Dam Safety Engineer, hydro safety staff, the
appropriate hydro operator and the appropriate plant manager. If a large-scale measure
requires replacement, a formal project plan, including a steering committee, may be
deemed appropriate.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 28 of 170
Hydro Safety
Business Case Justification Narrative Page 5 of 5
3.2 Provide and discuss the governance processes and people that will
provide oversight
This will be identified on a case-by-case basis, depending on the complexity and scale
of the proposed measure.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
This will be identified on a case-by-case basis, depending on the complexity and scale
of the proposed measure.

The undersigned acknowledge they have reviewed the Hydro Safety 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: Michele Drake
Title: Supervisor, Hydro Compliance
Services

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
7/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 29 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY
The major driver for this business case is regulatory. During a recent FERC annual
inspection, the inspector noticed a seeping joing in an airshaft and requested that Avista evaluate the internal plane stability of the intake and spillway dams. The analysis performed evaluates all loading conditions the dams may experience including full-pool (normal) operations, probable maximum flood (PMF), and
seismic conditions. The analysis revealed that Long Lake dam does not meet the
internal plane stability minimum safety factor during a PMF event. Avista submitted a preliminary study to the FERC and is waiting for final design before sending the FERC the full scope of the project and timeline to address mitigation. Avista is also currently revising the Spokane River PMF as well as perfoming a site specific seismic hazard assement to fully understand what the loading on the
facility is how how best to address any mitigation. Both of these studies are in their final stages and/or under the FERC review. Additonal investigation of three dimensional affects of the geometry of the facility is also actively being performed. The results of all of the aforementioned analyses will guide the direction of the project. The FERC expects Avista to develop a migitation plan to address the
stability issues and therefore thei project is mandatory. If this project does not
move forward, Avist’s relationship with the FERC will be heavily damagers and fines will likely result.
The recommended solution will be heavily informed of the above, however, is
anticipated to be some level of additional anchoring at the facility as well as possible added concrete mass to the dam structures. A high level construction feasibility study was conducted at the 20% design complete stages and was refined by a third party industry expert in dam stability and anchoring, and heavy civil construction Engineering Solutions. It was estimated that the construction
could be done in one year but more realisitically should be done over two years. The construction cost is estimated at roughly $17.16M and Engineering efforts at $3.99M. Total project costs have an overall estimate at complete cost of $31.42M. This estimate covers Avista labor, Capital Overheads, AFUDC, Engineering, Construction, and Water Stop repair effots associated with Stability.
VERSION HISTORY
Version Author Description Date Notes
1.0 PJ Henscheid Format existing BC into exec summary 7.6.20 5-year Capital Planning
Process
2.0 PJ Henscheid Completion of full BCJN document 7.31.20 5-year Capital Planning
Process

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 30 of 170
Long Lake – Stability Enhancement
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?
Long Lake dam does not meet the internal plane stability minimum safety factor during a PMF event. Additionally, Avista believes a large portion of water seepage in the concrete is related to deteriorated waterstops that were installed along the vertical construction joints during the original construction.
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 regulatory, mandatory & compliance.
Avista is subject to multiple Federal, State and Local environmental regulatory
programs. Avista is required by FERC to maintain facilities for generation and public safety, and at Long Lake this obligation is tied to maintaining structural concrete and steel components. The FERC license for Long Lake HED includes several operational requirements that depend on reliable operation of the generation units
as well as the intakes and spillgates.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
Not completing the Stability Enhancement Project will negatively impact Avista’s commitment to the FERC and risk compliance with Part 12 recommendation from
the Independent Consultant and Avista’s commitment to dam safety.
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.
Initial stability studies revealed that Long Lake dam does not meet FERC stability criteria during PMF and Post-Earthquake loading conditions. Success of the project
requires design and delivery of stability measures to bring the spillway and intake dams into compliance with FERC stability requirements. Stability measures that are
Requested Spend Amount $30.6M
Requested Spend Time Period 8 Years
Requesting Organization/Department J07/GPSS
Business Case Owner | Sponsor PJ Henschied | Andy Vickers
Sponsor Organization/Department A07/GPSS
Phase Planning
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 31 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 3 of 8
justified through a value engineering analysis, that satisfy FERC factors of safety for stability, and are properly constructed per plans and specification would be consider a success.
The initial design work considers some high level mitigation solutions; including adding post-tension anchors into bedrock, adding pressure relief drains, and adding
mass concrete to the dam structure itself. These options, or a combination thereof, can bring the dams into FERC stability compliance. No other solutions are known to exist for stabilizing the dam.
Finalizing the design parameters, and establishing a more defined budget will be essential in the success of project delivery and capital budget forecasting. To assist
in delivering the project on time and within our budget parameters, we will be looking for an alternative progressive project delivery method.
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.

The initial design work considers some high level mitigation solutions; including adding post-tension anchors into bedrock, adding pressure relief drains, and adding
mass concrete to the dam structure itself. These options, or a combination thereof,
can bring the dams into FERC stability compliance. No other solutions are known to exist for stabilizing the dam. 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 Start Complete
Alt 1 – Initial Anchor Design, Two Season
Construction schedule
$18.52M 10 2016 01 2024
Alt 2 – Initial Anchor Design, One Season
Construction schedule
$18.65M 10 2016 06 2023
Alt 2 – New Design, Anchors, Drains and Grouting $17.35M 10 2016 01 2024
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
The initial design work, value engineering, and constructability reviews, as well
as, industry studies, reports, and information gleaned from Avista’s peer dam
owners have all contributed to the development of the business case.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 32 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 4 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.
There are no anticipated Operations costs associated with the project. Value
engineering and design efforts are considering future maintenance costs associated with stability measures implemented as part of the design.
The project is anticipating the following costs:
2016: $117,912
2017: $217,322
2018: $548, 020
2019: $466,545
2020: $1.126M
2021: $4.205M
2022: $12.94M
2023: $11.54M
2024: $250,000

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
The primary business functions that will be impacted during the construction of the project are Hydro Plant Operations, Environmental & Permitting, Supply Chain, External Communications, and Power Supply. Detailed coordination and
planning efforts will take place during the course of the project planning and
construction phases.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
The Initial Design (Baseline) stabilization measures remain a highly
recommended stabilization measure for Long Lake Dam. Post-tensioned
anchors are a proven long-term solution for stabilizing dams. Based on current U.S. standards, post-tensioned anchors have negligible maintenance and monitoring costs. The 1989 intake anchor installations prove that posttensioned anchors are a realistic stabilization measure for Long Lake Dam.
The VE screening determined that added mass or drains are not viable stand-
alone measures.
Some degree of post-tensioned anchoring is needed. Combining added mass or drains with posttensioned anchors was considered. The combination of adding mass and post-tensioned anchors is not recommended due to the expected increase in construction cost and longer construction schedule. A
combination of spillway shallow and deep post-tensioned anchors was considered but is not recommended due to the risk of compromising the stability of a lower internal plane near the end of the shallow anchors.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 33 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 5 of 8
There is potential benefit with the combination of drains and post-tensioned anchors at the spillway, but there is insufficient evidence to recommend this alternative over the Initial Design based solely on the VE screening. A ROM construction cost estimate prepared for the combination measure of drains and post-tensioned anchors to allow any capital cost savings to be weighed against
potential regulatory risk associated with drains. Due to the lack of certainty around drain efficiency and long term maintenance costs, drains are not a recommended 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. spend, and transfers to plant by year.
Initial design efforts and investigation started in 2016 and are anticipated to be completed in late 2021 / early 2022. Construction is anticipated to begin shortly after the completion of the design with an estimated completion in late 2023. The project team will look at options to break construction packages into phases
such that segments can be placed into service throughout the project, rather than at the end.

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. The internal plane stability of dams is a concern around the region after the 2014 Wanapum Dam spillway crack incident. This business case is to address stability concerns at the Long Lake Dam.

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, Dam Safety
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 34 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 6 of 8
- 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.

3.1 Steering Committee or Advisory Group Information
▪ Project Sponsor:
• Andy Vickers –Director GPSS

▪ Steering Committee:
• Jacob Reidt – Manager Project Delivery
• Bob Weisbeck – Manager of Hydro Ops & Maintenance
• Meghan Lunney – Spokane River License Manager

▪ Project Manager:
• Michael Truex – Generation Project Delivery

▪ Key Project Stakeholders:
• Bob Weisbeck – Manager of Hydro Ops & Maintenance
• Gio Del Papa – Senior Civil Engineer
• Brian Vandenburg – Manager Plant Operations Hydro – Lower Spokane
• Greg Hesler – Senior Counsell II
• Michele Drake – Supervisor Hydro Compliance
• Kevin Powell – Chief Operator
• Tia Benjamin – GPSS Budget Specialist
• 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:
• Robin Bekkedahl – Environmental Scientist
• Gio Del Papa – Senior Civil Engineer II (Avista Project Technical Lead & QCIP
Mgr)
• Paul Lennemann – Chief Dam Safety Engineer
• Allyson Tanzer – Project Manager
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 35 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 7 of 8
• Ryan Traylor – Project Coordinator
• Michael Truex – Project Manager
• Alden Labs –Engineer of Record
• CM/Inspector – TBD
• STRATA – Geotechnical Engineer
• Nuss Engineering LLC – Dam Stability Technical Advisor
• Engineering Solutions – Construction Technical Advisor
• LCI Seismic – Seismic Engineer & Technical Lead
• Construction Contractor - TBD
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.

The undersigned acknowledge they have reviewed the Long Lake Stability
Enhancement 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: 7.31.20
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 36 of 170
Long Lake – Stability Enhancement
Business Case Justification Narrative Page 8 of 8
Print Name: PJ Henscheid
Title: Manager, Civil and Mechanical Engr
Role: Business Case Owner

Signature: Date: 7.31.20
Print Name: Andy Vickers
Title: Director, GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 37 of 170
GPSS_KF_Ash Landfill Expansion
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

Kettle Falls Generation Station burns on average of 450,000 green tons of wood waste annually. This combustion process creates roughly 30,000 cubic yards of ash that is trucked and stored at the 177-acre parcel south of the plant site. The landfill area is approximately 15 acres nested inside of a 42-acre fenced parcel designated for landfill
operations and development. Ash has been generated from the plant and stored at the
area landfill since 1986 consisting of three engineered cells (Phase 1-3). Phases 1 and 2 were closed and covered in 2003 in accordance with WAC regulations. In February 2020 a permit modification request was submitted with the Department of Ecology to increase the slope of Phase 3 from a 4:1 to a 3:1. This request would increase the capacity of the
current Phase 3 by 110,000 cubic yards. On May 5th, 2020 the Department of Ecology
approved the request to increase the Phase 3 slope. Calculations with the newly approved slope and existing air space revealed Phase 3 reaching full capacity in 2025.

Environmental Information Logistics EIL and Schwyn Environmental Services was hired
to assist in the planning and budgeting efforts to create a Landfill Master Plan for current
operations, closure of Phase 3 and engineering and design of Phase 4. The creation of the new Phase 4 landfill area creates space for ash disposal at the current rate of nearly 40-50 years of disposal. The Phase 4 landfill is the lowest cost impact to the customers for disposal of the ash when comparing the costs of disposal into the nearest acceptable
landfill. Disposal costs would exceed 2 million per year of O&M expense if Phase 4 was
not constructed.

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.

See attached Landfill Master Plan for more information and details.

VERSION HISTORY
Version uthor Description Date Notes
Draft Greg Wiggins GPSS_KF_Ash Landfill Expansion 7/9/2020 Reference Master Landfill Plan

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 38 of 170
GPSS_KF_Ash Landfill Expansion
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?
The Kettle Falls Generation Station is a renewable resource for Avista that uses
biomass for its primary fuel source. The combustion process burning wood
creates ash in the volume of 30,000 cubic yards annually depending on plant dispatch.
The current ash landfill is reaching its full capacity and is expected to be completely filled between 2025 to 2028 depending on plant dispatch and ash
production.
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 to this project include Mandatory & Compliance, Performance & Capacity and Asset Condition. They Phase 3 landfill will require mandatory proper closure following the Department of Ecology guidelines for retiring landfills. Without having a disposal site for the ash, the plant would be forced to
close or operate as a natural gas fire unit which would lose 53 MW’s of
renewable resources from Avista’s portfolio. Estimated costs associated to haul the ash to an area landfill exceed 2 million O&M expense annually. By constructing the new expansion operating costs will significantly less.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The landfill is nearing capacity. With permitting, engineering and construction the project would need to begin with permitting and engineering in 2021 to ensure we meet final construction within the expected life of the current Phase 3 disposal area.
Requested Spend Amount $10,850,000
Requested Spend Time Period 5 years
Requesting Organization/Department K07 / GPSS
Business Case Owner | Sponsor Greg Wiggins | Andy Vickers
Sponsor Organization/Department K07 / GPSS
Phase Initiation
Category Project
Driver Mandatory & Compliance
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 39 of 170
GPSS_KF_Ash Landfill Expansion
Business Case Justification Narrative 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.
Work has been ongoing since 2019 with third party Landfill consultants EIL and Schwyn Environmental. Avista Environmental support and plant staff have been
modeling and tracking current fill rates for 20+ years and have data to model the time in which the landfill will reach full capacity. EIL has developed a Master Landfill Plan for the closure of Phase 3 and the development of Phase 4 and ongoing associated operating costs with the new landfill.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
EIL Kettle Falls Master Landfill Plan has been completed with input from Avista Environmental
Team and Plant historical data.
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 proposed solution to construct a new Phase 4 lined landfill built to current standards will incorporate the closure costs of Phase 3 as part of the construction of
new disposal area. Referenced in the Kettle Falls Master Landfill Plan as Concept
2A is to construct Phase 4 utilizing the air space between the two cells. In this option some of the Phase 3 closure costs are absorbed into the additional space created between the two independent cells. The overlay of Phase 3 becomes part of the leachate collection system for Phase 4 and increase. This increase would add an
additional 10 years of storage to Phase 4 creating enough air space for 40 to 50 years
assuming a filling rate of 30,000 to 40,000 cubic yards per year.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 40 of 170
GPSS_KF_Ash Landfill Expansion
Business Case Justification Narrative Page 4 of 7
Option Capital Cost Start Complete
Construct Phase 4 Concept 2A KF Ash Landfill $10.85M 03/2021 11/2025
Construct Phase 4 Concept 1 KF Ash Landfill $10M 03/2021 11/2025
Close Phase 3 & begin Hauling Ash to Area Landfill $2M 06/2025 06/2026
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Drone data was used to calculate the remaining air space of the current landfill area. That data was used to set a timeline until the current Phase 3 will reach its maximum
fill capacity date based on current operating data. With an end date determined and the EIL Master Landfill Plan a schedule of projects have been lined out to meet the need of having area to dispose of the plant ash without disrupting the operations and output of the plant or incurring significant disposal fees to area landfills.
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.

Year Requested Change Proposed Work
2021 $650,000 Engineering and Permitting
2022 $2,000,000 Construction of Leachate Pond
2023 $2,100,000 Phase 3 Overlay and Closure
2024 $4,200,000 Phase 4 Construction
2025 $1,900,000 Phase 3B Final Cover Construction

Due to new regulations regarding landfill design the proposed solution will be a lined landfill with will generate leachate collected in the bottom of the landfill
which will need to be processed. Current studies are ongoing on the actual
system or process that will be used to process the wastewater which may create an O&M increase.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Kettle Falls Generating Station will be able to continue to operate and serve Avista customers with 53 MW’s of renewable power without interruption during the project.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 41 of 170
GPSS_KF_Ash Landfill Expansion
Business Case Justification Narrative Page 5 of 7
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Option 2 Concept 1 Phase 4 stand-alone cell located to the east of Phase 3. This design would create and entirely
separate landfill which will follow new Limited Purpose Landfill regulations that require an engineered base liner and leachate collection system. Phase 3 shown in green will continue to be in
operations as Phase 4 shown in yellow is developed. Phase 3 will be closed after operations shift to Phase 4. For a small increase in overall cost the proposed plan would increase the overall lifespan of the landfill by 15 years.
Option 3 consisted of closure of the Phase 3 landfill area and then disposing ash at an area landfill which would require an increase in O&M expense near 2 million annually.
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.
Kettle Falls Generating Station is a valuable resource for Avista. The plant generates up to 53 MW’s of base loaded renewable power to help meet Avista vision
of being 100% carbon neutral and a renewable.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 42 of 170
GPSS_KF_Ash Landfill Expansion
Business Case Justification Narrative Page 6 of 7
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 be a collaborative effort with GPSS and Environmental
Departments. The project core Team has been working with third party consultants on the Kettle Falls Master Landfill Plan in developing the project. This project will utilize a Steering Committee and a Project Manager to monitor the project scope, schedule and budget.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Primary Stakeholders include GPSS, Environmental, EIL, Craig Schwyn Environmental, Department of Ecology, Tri - County Health
2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
Steering committee will include both GPSS and Environmental Senior Leadership.
3.2 Provide and discuss the governance processes and people that will
provide oversight
This project will be managed utilizing the GPSS Project Delivery process. An assigned Project Manager will be assigned to the project to facilitate meetings with the project core Team. Any impacts to the project scope, schedule or budget will be
brought to the Steering Committee for approval and direction.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Documentation will follow the GPSS Project Delivery process with monthly status reports.

The undersigned acknowledge they have reviewed the GPSS_KF_Ash Landfill
Expansion 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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 43 of 170
GPSS_KF_Ash Landfill Expansion
Business Case Justification Narrative Page 7 of 7
Signature:
Date: 7/10/2020
Print Name: Thomas C Dempsey
Title: Mgr. Thermal Ops & Maint
Role: Business Case Owner

Signature:

Date: 7/10/2020
Print Name: Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 44 of 170
GPSS_Base Load Thermal Program
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

Avista’s Base Load Thermal plants include Coyote Springs 2 and Kettle Falls Generating Station. These two base loaded plants have uniquely different operational flexibility to best serve Avista’s customers energy demands. Coyote
Springs 2 is a natural gas fired combined cycle unit which generates 300 MW’s. It
is equipped with automation to adjustment unit output to match changing system
loads and other types of services necessary to provide a stable electric grid. Kettle Falls is a base loaded renewable resource with the ability to store energy for long periods of time to optimize energy markets to best serve Avista Renewable needs.
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. These projects are also reviewed in an owner committee setting during meetings at the plant that
take place on a monthly basis. Kettle Falls Generation Station projects are identified
and prioritized through the plant Budget Committee. Both plants utilize the GPSS ranking matrix system to evaluate the projects.
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 which are identified are then 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

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 45 of 170
GPSS_Base Load Thermal Program
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?
This program is important in providing funding to support the replacement of critical assets and systems for the reliable operations of these facilities. These two plants provide full load output during peak power demands when other resources are limited. This program allows for smaller strategic asset management and planning while allowing for emergent funding of failed plant
assets. It is difficult to predict failures and unscheduled problems of operating thermal generating facilities this allows for quick access to funding when breakdown occur.
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 thermal facilities. The reliable 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 $14,880,000
Requested Spend Time Period 5 years
Requesting Organization/Department C06, K07 / GPSS
Business Case Owner | Sponsor Thomas Dempsey | Andy Vickers
Sponsor Organization/Department A07 / GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 46 of 170
GPSS_Base Load Thermal Program
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 unit availability. Both plants have seen increased capacity and output over the years.

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. About 75% of the annual budget is
planned due to Asset Condition with 25% reserved for Failed Plant that arise during the year. Many of these projects are small in scope and budget.

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 2021-2022; spend $3,100,000 per year in 2023-2025.

Option Capital Cost Start Complete
Base Load Thermal Program 14,880,000 01/2021 12/2025
Individual Capital Projects 14,880,000 01/2021 12/2025

2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
Maximo is the system of record for recording failed plant assets. Work orders are used to show trends in increased maintenance or complete failures. Some projects are driven by asset age and are no longer supported by the OEM.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 47 of 170
GPSS_Base Load Thermal Program
Business Case Justification Narrative Page 4 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.

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 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 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 30-50 projects a year funded by the program between the two plants. 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 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 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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 48 of 170
GPSS_Base Load Thermal Program
Business Case Justification Narrative Page 5 of 8
The projects in this program for Coyote Springs 2 and Kettle Falls typically take place during the annual outages, which are typically in May-June of each year. There are projects that are completed throughout the year without requiring a unit outage by utilizing standby equipment.

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 thermal plants reliable and available.
By doing this we support our mission of improving our customer’s lives through innovative energy solutions which includes thermal generation. 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.

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

Historically the two plant have been able to work within a 3 million annual budget allocation. Some years one plant is in need of more and adjustments are made with the other plant to accommodate the need. Since the inception of the Base Load Program funding Coyote Springs and Kettle Falls Generation Station has been able to work well in making continued improvement to the plant assets
through small incremental steps. Each individual project is reviewed by the Plant Manager the approved by the GPSS Thermal Operations and Maintenance Manager prior to beginning work.
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.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 49 of 170
GPSS_Base Load Thermal Program
Business Case Justification Narrative Page 6 of 8

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, Assistant 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.
For Coyote Springs 2, 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 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, 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 include 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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 50 of 170
GPSS_Base Load Thermal Program
Business Case Justification Narrative Page 7 of 8
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 include 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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 51 of 170
GPSS_Base Load Thermal Program
Business Case Justification Narrative Page 8 of 8
changes to this will be coordinated with and approved by the undersigned or their designated representatives.

Signature:

Date: 7/10/2020
Print Name: Thomas Dempsey
Title: Manager of Thermal Ops & Maint
Role: Business Case Owner

Signature:

Date: 7/10/2020
Print Name: Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 52 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 1 of 10
EXECUTIVE SUMMARY

Avista has experienced multiple catastrophic GSU transformer failures since the plant’s
construction in the early 2000’s. The purpose of this project is to replace the currently in-service
transformer, “T4”, which exhibited unacceptably high gassing levels after only being in service a
couple of months following the failure of it’s twin that failed after approximately nine years of
service “T3”. Coyote Springs serves Washington and Idaho electric customers. After a detailed
financial analysis was performed, the recommended solution is to replace the existing three-phase
dual-wound transformer, T4, with three single phase dual-wound transformers. As of the June
2020 (version 3.2) update to this Business Case, the estimated cost is expected to be $21,400,000
which includes replacement of T4 as well as the purchase of a spare unit.

The financial analysis included a calculation of Customer Internal Rate of Return as compared to
all possible alternative options. The CIRR of the proposed solution was the highest. Subjectively
stated, this project will result in higher reliability and reduced power supply expense. The timeline
is critical given the current gassing state of T4. The risk of not approving this business case is the
likely failure of T4 with a corresponding outage of 18-24 months.
VERSION HISTORY
Version Author Description Date Notes
1.0 Mike Mecham Initial draft of original business case 6.25.19 Signed/approved
2.0 Thomas Dempsey Updated Budget 9.19.19
3.0 Thomas Dempsey Updated Budget 12.23.19
3.1 Kara Heatherly Conversion to new format 6.20.20 Includes budget update
3.2 Thomas Dempsey Final Updates to new format 7/7/2020

GENERAL INFORMATION
Requested Spend Amount $21,400,000
Requested Spend Time Period 2 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Thomas Dempsey | Andy Vickers
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Failed Plant & Operations
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 53 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 2 of 10
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Coyote Springs 2 currently uses a single three phase transformer (GSU) configuration for power transformation to the BPA electric grid. Subsequent initial GSU energization in 2002, we have experienced seven GSU failures. In 2018, a spare transformer (T4) was placed in service subsequent the failure of Transformer 3 (T3). After being in service for one month, T4 saw a spike in combustible gases. Gases are now being closely monitored and the transformer is currently limited to 90% capacity.

The Business Problem is that we now have an underperforming transformer that is not at full capacity and which is exhibiting troubling gassing behavior. We consider the risk of failure to be significantly higher than acceptable. We also have no spare at this time- a failure without a spare could lead to an 18 month or longer outage.

The table below is an overview of the historical failures of the 4 three-phase transformers purchased and installed at Coyote Springs 2 since construction:

1.2 Discuss the major drivers of the business case and the benefits to the customer
Failed Plant Conditions: one of the primary drivers to our selection of this preferred alternative is the
likelihood of the risk exposure that remains with an “in kind” three-phase replacement. It is in Avista’s
best interested to spend these resources on a more reliable solution.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 54 of 170
CS2 Single Phase Transformer
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
This work is needed immediately given the condition of the existing transformer and the lack of a reliable spare. If the existing transformer fails now we would expect to see an 18-24 month outage with its associated power supply expense implications. See business problem details in Section 1.1 and additional data and analysis details provided in Section 2.1.
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.
• Power Output- After the project is complete, the operating limit of the plant will be increased to 320 MW- This is an immediate increase and an appropriate objective
measure.
• Gassing Levels- The new transformers will be outfitted with Serveron Gas Monitoring equipment to ensure that we are not experiencing interal hot spots or arcing that could lead to catastrophic failure.
• Reliabilty- We expect the new transformers to provide reliable service immediately and into the future, therefore equipment availability is the third such measure that can be used to determine if the investment has met the stated objectives.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Please see the appendices listed under Section 2.1
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 project provides for replacement of the failed T3 as well as the currently
operating but gassing T4. T3 failed catastrophically due to an internal fault. See Figure 1 below that clearly shows internal arcing damage. T4, which is of nearly identical construction as T3, is currently gassing at dangerous levels. If left unchecked, we expect the gasses could reach explosive levels within a two year period. We are carefully monitoring gassing levels to make sure they do not reach these explosive limits during the period of time we are waiting to install the new
single phase units. Figure 2 shows the gassing levels currently being seen in T4.
In June 2019 we performed a “dialysis” of sorts as a mitigative measure to prevent the dissolved gasses from reaching an explosive level until such time as the transformer can be replaced.

Figure 1- T3 Static Shield Ring Catastrophic Internal Damage
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 55 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 4 of 10

Figure 2- T4 Gassing Trend

1.6 Describe what metrics, data, analysis or information was considered when preparing this capital request.

Avista has experienced multiple failures of GSU transformers in service at Coyote Springs despite proper operations and maintenance activities.

• The new transformers will collectively be higher in capacity than the prior transformers at Coyote to provide a higher safety margin and also to allow for technology improvements (which historically have been typical) that allow for higher output at higher efficiency.
• The three phase transformers have proven to be very expensive and difficult to move due to their size and weight. In an email exchange with BPA where Avista asked about use of three
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 56 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 5 of 10
phase transformers in this application, BPA indicated they would not use transformers of this size due to transportation difficulty.

• Changing to a single phase design versus keeping the existing three phase configuration will
be challenging- but given the large number of failures Avista believes it is prudent to abandon the existing configuration. To that end, the financial analysis assumptions regarding three phase transformer reliability reflect Avista’s experience at Coyote Springs 2.
• The difficulty and enormous complexity of mobilization associated with the three phase solution results in longer duration outages than those associated with individual single phase transformers.

• Avista and its expert consultants determined that manufacturing defects were the likely culprit with respect to the failures of T1 and T2. The failure mechanism for T3 is currently being evaluated. T4 is in service, however it is gassing at dangerous levels. Avista cannot rule out a fundamental application flaw associated with what Siemens and others have described as a
somewhat “unusual” configuration. It is possible that this dual low voltage with 500KV high side configuration approach has as yet-to-be determined fundamental flaws. Avista can no longer rule out this possibility given the number of failures we have experienced. PGE, with its single phase transformers is interconnected with the grid at a virtually identical location as unit 2, and they have experienced no failures in 20+ years of operation.
Additional detail and project background can be found in the associate documents:
• Appendix I 20191223 Power Supply Asset Management Consolidated Financial Analysis
• Appendix II David Nichols Engineering Recommendation
• Appendix III Avista-CoyoteSpgs-GSU-Replcmt-Concept-Report_Final_Rpt-w-ATT rev.pdf
• Appendix IV 20191223 Decision Tree Narrative
• Appendix V 20200513 New Financial Analysis of T5 Project.docx
1.7 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.
In accordance with the detailed project schedule, annual projected capital expenditures for remaining scope are as identified in the 5-year CPG budget:
• 2020 - $9,900,000
• 2021 - $11,500,000
With respect to O&M reduction, the primary reduction to customer expense is the reduction in power supply expense. The financial analysis includes such risk modified expenses. The financial analysis is included as Appendix I.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 57 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 6 of 10
1.8 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
This project requires internal and external resources for it to be completed successfully.
1.9 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
Note: The following table of results and the associated explanations represent the initial results from the initial study associated with this project. These numbers were based on our best estimates at the time. As we have gotten further into the project, costs have increased due a number of reasons, including increased fire protection requirements and firm bids
from suppliers that were higher than initially projected by Avista’s Consulting Engineer. The options were subsequently reviewed and Option V remains the best choice for
customers. A summary of the new analysis performed may be found in this document:
20200513 New Financial Analysis of T5 Project.docx.

Option Capital Cost NPV of Net Plant Margin
Relative CIRR Start Complete
I. Repair T3, no repair of T4 $6.2 Million $209.0 Million 4.0% 10/2019 6/2020
II. Purchase one (1) new 3-
phase, no repair of T4 $8.0 Million $206.5 Million 5.8% 10/2019 12/2020
III. Purchase one (1) new 3-
phase, Repair T3 $13.7 Million $206.3 Million 5.8% 10/2019 6/2022
IV. Purchase two (2) new 3-
phase units $13.1 Million $207.2
Million
6.2% 9/2019 12/2020
V. Purchase four (4) single-
phase transformers
(includes spare)
$15.1 Million $213.9 Million 9.4%

9/2019 6/2021

Options I- Eliminated due to high power supply risk and relatively lower IRR than the preferred option.

Option II- Eliminated due to high power supply risk and relatively lower IRR than the preferred option.

Option III- Eliminated because Option IV provides superior reliability at lower cost and lacks the opportunity for a double redundant emergency spare. This option also has a relatively lower IRR than the preferred option.

Option IV- Siemens-Austria provided an indicative price for two new 3-phase units at a delivered and commissioned at price of about $9.2 million (Option IV). After other site costs, Avista engineering, and other costs are considered, the price estimate is $13.1 million. Furthermore, Avista expects that a choice to begin a new procurement process and a path towards a 3-phase solution would cause significant power supply risk for the summer of 2021. These considerations point further towards Option V as the best solution. Option IV eliminated because even though this option provides the potential for a double redundant emergency spare, it still utilizes the 3-phase dual wound design that has proven unreliable at Coyote Springs in this configuration. This option also has a relatively lower IRR than the preferred option.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 58 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 7 of 10

Option V- Option 5 is the preferred option as it has the highest relative IRR of any of the options. This option uses single phase transformers that are smaller and much easier to transport. This is the same configuration that is used on Unit 1 which have proven highly reliable over time. This option also allows for a double redundant emergency backup using T4 (this would require iso-phase bus reconfiguration and would only be used if single phase lead times dictated the need).

Siemens-Austria and SMIT-Netherlands were the finalists for Option V. David Nichols and Rob Selby
from Avista as well as Avista’s expert consultant Pierre Feghali visited both factories. While both appeared to be of high quality, Siemens-Austria stood out as a top of class facility with extensive quality control mechanisms in place. It is therefore the factory of choice the transformer supply costs are referenced to.

RECOMMENDATION: Purchase and install four (4) single phase transformers and all supporting equipment (coolers, fans, instrumentation, bushings). Included in the request is all of the design engineering, all equipment modification including containments, fire suppression, electrical protection, isophase bus, and all supporting equipment.

1.10 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.
Project planning and design activities began in 2019. In order to minimize outage activities during critical operations windows, the project execution plan will include a two-phased outage during the
Spring/Summer of 2020 and 2021.
The 2020 outage will consist of early civil/structural foundation work for the T5A and C locations and
T5A, B, and C containment where possible.
The 2021 outage will include all civil/structural activities that require T4 to be out of service and
relocated, as well as all other activities (including but not limited to): placement of new transformers, installation of IsoPhase Bus, new deluge system piping, and High Voltage Bus.
Project is expected to be completed and Coyote Springs Unit 2 back online by the end of June 2021.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 59 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 8 of 10
1.11 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. This project does so by:
• Minimizing our exposure to unnecessary breaks in service
• Avoiding inflated power purchase prices and subsequent increased costs to our customers
• Minimizing the risk of potentially catastrophic failure
• Eliminating ongoing operations safety risks, and
• Eliminating unnecessarily escalating operating costs
Strategic Initiatives: 1. Safe and Reliable Infastructure, 2. Responsible Resources.
1.12 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
A number of alternatives were considered. The recommended course of action represents the highest value of CIRR. See Appendix I and Appendix II.
With respect to investment prudency review; as of version 3.2 of this business case,the project budget was increased to $21.4 million. We conducted a thorough review as well as a new
financial analysis to review whether going forward was the best course of action. It was. A complete discussion of this process and its results is provided in Appendix V- 20200513 New
Financial Analysis of T5 Project.docx. A summary table exerpt from that document is provided below:

1.13 Supplemental Information

1.13.1 Identify customers and stakeholders that interface with the business case
There is no customer interface with respect to this project. Key stakeholders include the Avista Power Supply group as well as GPSS.

Options Capital Cost $M / Plant Net Market Value $M
Options Original Analysis Revised Analysis
Option I- Rebuild T3; T4 Spare 6.2/209 Rejected
Option II- New 3Ph, T4 Spare 8/206.5 Rejected
Option III- New 3Ph, Repair T3 13.7/206.3 17.1/202.5
Option IV- Two new 3Ph 13.1/207.2 17.6/202.1
Option V- Single Phase 15.1/213.9 21.4/206.6

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 60 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 9 of 10
1.13.2 Identify any related Business Cases
This Business Case represents the new 2020 format and thus it replaces the prior
approved Business Case titled, “BCJN_CS2 Single Phase Transformer_signed 201912”.
2.1 Steering Committee or Advisory Group Information
Prior to July 2020, executive level oversight of this project was provided on an as-needed basis by Power Supply Management, GPSS Management, and Energy Resources Executive Leadership. Initial project estimates and project execution frameworks were developed by Avista’s consultant engineer and project manager, Black and Veatch.
A formal Steering Committee has been established as of July 2020 and will meet on a quarterly basis over the next year to review project status.
As of March 2020, this project has been assigned an Avista Project Manager responsible for the management and regular reporting of scope, schedule and budget deviations from the current project execution plan.
2.2 Provide and discuss the governance processes and people that will provide oversight
Executive level scope, schedule, & budget oversight is provided by the Steering Committee on a Quarterly basis. Ongoing senior management is provided by the Manager of Thermal Operations. Day to day project oversight is provided by the assigned Project Manager.
2.3 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 Mananger of Thermal Operations & Maintenance when and if determined to be necessary by the role definitions above. Regular updates will be provided to management by the PM team as project scope, schedule and budget are defined, and throughout the course of the project execution.
The undersigned acknowledge they have reviewed the CS2 Single Phase Transformer 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: 7/10/2020
Print Name: Thomas Dempsey
Title: Manager, Thermal Operations
Role: Business Case Owner

Signature:

Date: 7/10/2020
Print Name: Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 61 of 170
CS2 Single Phase Transformer
Business Case Justification Narrative Page 10 of 10

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 62 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 63 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 64 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 65 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 66 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 67 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 68 of 170
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 69 of 170
Base Load Hydro
1 GENERAL INFORMATION
Requested Spend Amount $1,149,000
Requesting Organ ization/Department Generation Production and Substation Support
Business Case Owner Mike Magruder
Business Case Sponsor Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Gategory Program
Driver Asset Condition
1.1 Steering Gommittee or Advisory Group lnformation
Most projects are proposed through Operations and Engineering. The projects are vetted
holistically by Operations and Engineering to evaluate the issue, determine available
options, confirm prudency, and bring the potential solutions forward for discussion with the
Advisory Group consisting of the Plant Managers and the Manager of Hydro Operations. A
similar vetting process is followed for funding emergency projects with the impacted
stakeholders included.
Over the course of the year, the program funding is actively managed by the Manager of
Hydro Operations through monthly analysis and reporting for end of year expected spend.
2 BUSINESS PROBLEM
Avista's Base Load Hydro (or Base Hydro) program includes the Post Falls, Upper Falls,
Monroe Street, and Nine Mile Hydroelectric Developments. These are all located on the
upper Spokane River and are "run of river" plants which require them to have a constant
water level in their forebay. It also includes minor 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 purpose of this program is provide funding for these plants to accomplish the objectives
of keeping operating expenses as low as possible and maintain a level of reliability as
indicated by the Equivalent Availability Factor (EAF) in the graph below. This program
covers the smaller capital expenditures and upgrades required to safely and reliably operate
the Upper Spokane River plants and continue their low cost. Projects completed under this
program include replacement of failed equipment and small capital upgrades to plant
facilities. The business driver for this program is a combination of Asset Condition, Failed
(or Failing) Plant, and addressing operations deficiencies.. Most of these projects are short
in duration, typically well within the budget year, and many are reactionary to plant
operations issues.
Business Case Justification Narrative Page 1 of5
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 70 of 170
Base Load Hydro
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Examples of projects completed in20l6 or in progress under this business case include:
o Monroe St. - V/ater Drain and Diversion Installation. This project captured high
flows on the site that were washing away some of the visitor amenities.
o Nine Mile - Replace Failed Spillway Gate Controls. This project will replace failed
controls that allow the spillway to automatically adjust to maintain a forebay level.
. Upper Falls * Upgrade Headgate Camera. This replaced a non-functioning camera
used for some area surveillance and to observe the trash rake operation on the intake.
o Post Falls - Replace Switch Building Drain Field. This project is to move ponding of
water away from the foundation structure to maintain the integrity of the building.
o Nine Mile - Install Roof Safety Handrail. This addresses a personnel safety item.
o Post Falls - Install N. Channel Downstream Warning System. This is a system that
warns the public in the event of a start of a spill or a significant increase in spill at the
site.
The Program funding requests are submitted to the Capital Planning Group (CPG) through
the business case review process. The business case expenditures over the last 5 years are
shown below.
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Business Case Justification Narrative Page 2 of 5
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 71 of 170
Base Load Hydro
Base Load F{ydro Hxpenditures
Previous Five Years
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2013 2015 201,6
3 PROPOSAL AND RECOMMENDED SOLUTION
These base load hydro plants are among the oldest plants in Avista's generating fleet. The
option to "Do Nothing" is impractical in that existing machinery and systems periodically
fail and are required to be replaced. Having no costs allocated to address those concerns is
impractical.
The second proposal is to continue with the Base Hydro program business case as it is
intended for asset condition, failed plant and operations. The program is actively managed
and the vetting process considers all options for projects including doing the project under
maintenance, the Base Hydro program, or a specific project business case.
The last proposal to eliminate funding for this program introduces greater risk to the ongoing
operation of the plants by reducing the efficiency of operations and administration to set up
and execute the required projects, especially for failed plant and operations. The program
gives us the flexibility to respond quickly and prudently.
The recommended option to pursue is the second proposal to continue with the Base Hydro
program business case as it is intended for asset condition, failed plant and operations. The
program is actively managed and the vetting process considers all options for projects
including doing the project under maintenance, the Base Hydro program, or a specific project
201.42-OL2
24fl 20'13 zA14 20rõ 20t6
$631,961 $905,557 $664,783 9342,194 $394,849
Option Capltal GoEt Start Complete
Do nothing $0
Maintain Existing Base Hydro Program Buslness Case $350k - $1.15M Annual Annual
Make all small projecfs as sfandalone projects $s.1M - $5.9M Annual Annual
Business Case Justification Narrative Page 3 of 5
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 72 of 170
Base Load Hydro
business case. The program offers greafer efficiency to manage "drop-in" or emergency
projects allowing for better response time.
The annual requested budget amount is conservative to cover potential large expenditures
that do not require a new project business case to be developed. The annual amount is
reasonable, especially given that the program is actively managed and there is a means to
release or request funds through the CPG.
Business Case Justification Narrative Page 4 of 5
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 73 of 170
Base Load Hydro
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Base Load Hydro Business
Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
ll¡.. t{qtu Oos â tl4¿"*e*.*(-/Business Case Owner
e?r
O irn cfo, 6 PSs
Business Case Sponsor
Date fl re /en,7
Date
Template Version: 03107 12017
5 VERSION HISTORY
Vereion lmplemented
By
Revision
Date
Approved
BY
Approval
Date
Reason
1.0 Mike Magruder 03117117 Jacob Reidt 04t19t2017 lnitialversion
Business Case Justification Narrative Page 5.of 5
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 74 of 170
Cabinet Gorge 15kV Bus Replacement
1 GENERAL INFORMATION
Requested Spend Amount $1,200,000
Requesting Organization/Department GPSS
Business Case Owner Glen Farmer
Business Case Sponsor Andy Vickers
Sponsor Organization/Department GPSS
Category Project
Driver Performance & Capacity
1.1 Steering Committee or Advisory Group Information
As generating plants are managed by the Generation, Production, and Substation
Support group, they provide energy and other services used by Power Supply. The
steering committee for this project will consist the Hydro Operations and
Maintenance Manager, Project Delivery Manger and the Maintenance Management
and Construction Manager.
2 BUSINESS PROBLEM
• During the design of the Cabinet Gorge Station Service Project, we had
planned to raise this horizontal bus by 5 feet to allow for the Station Service
equipment to be installed within these bus rooms.
• Further investigation is was discovered that the main horizontal bus between
the generators and the GSU transformers was underrated compared the
generator and circuit breaker ratings by approximately 10%.
• This led to the development of the replacement bus alternative to upgrade
the 15kV bus to 4,000 Amps to be consistent with the generator machine
ratings and GCB ratings.
3 PROPOSAL AND RECOMMENDED SOLUTION
Do nothing
Replace the 15kV Bus A (2021) and Bus B (2022)
Raise the existing 15kV Bus A (2021) and Bus B
(2022)
Business Case Justification Narrative
Capital Cost Tob1fCost
inclu.~i11g
····9utages
$0
$1,200,000 $1,230,000
$1,400.000 $1,700,000
10/2020 12/2022
10/2020 12/2022
Page 1 of 4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 75 of 170
Cabinet Gorge 15kV Bus Replacement
Two of the major design requirements for the Cabinet Gorge Station Service Project
are contributing factors that has led to the development of this new 15kV Bus
Replacement Project:
• Build as much of the new station service system as possible while the existing
station service equipment remains in service. The benefit of this construction
approach will greatly reduce generation unit outages from several months to
just a few weeks.
• Remove oil-filled equipment from the outdoor powerhouse deck. This
requirement is based on the extensive amount of water that the powerhouse
deck receives during spill season with the modified spillways now in service
for TOG abatement and is intended to reduce risk of potential oil spills.
This approach requires that we find new locations for the planned station service
equipment. The Station Service Project Team's recommendation was to use the
bus rooms at Cabinet for installing the new dry-type station service transformers
and the Power Centers to help minimize unit outage time and also removes the
existing oil filled station service transformers off the deck.
In order to be able to use the bus rooms at Cabinet, we need to move the existing
15kV bus. We did look at just removing and replacing a section of bus to allow the
equipment to be moved into the bus rooms. However, this option would not provide
adequate safe working clearance around the equipment if the bus remains in its
current location, and was disregarded as a viable alternative.
In order to resolve this issue of moving the 15kV generator bus to install the
proposed station service project equipment in these bus rooms, we evaluated two
alternatives: 1.) Raising the existing 3,000 Amp bus; and 2.) Replacing the bus with
a new 4,000 Amp bus.
Alternative 1.) Raise the existing 3,000 Amp 15kV bus. This alternative was not
chosen based on the following:
• Highest cost alternative
• Requires up to an 8 week outage for two units. Outage time is rather long as
we would have to remove all of the bus sessions in 7 foot sections, install
new structural steel hangers. Then re-install all of the bus section by section.
Then add the vertical transition boxes to connect to the existing generator
disconnects and GSU B-Phase bus.
• Does not resolve concerns over existing bus being marginally rated.
• Has a higher level of risk with damaging the aged brown glass insulators
during disassembly and reassembly of the bus sections.
Business Case Justification Narrative Page 2 of4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 76 of 170
Cabinet Gorge 15kV Bus Replacement
• Has a higher level of seismic risk as this existing equipment was not designed
to today's seismic standards.
Alternative 2.) Replace the existing 15kV bus with new 4,000 Amp segregated bus.
This is the recommended alternative based on the following:
• It's the least cost alternative
• Upgrades bus ratings to be aligned with GCB's and Generators
• Only requires a 6 day outage. This is based on the construction method of
installing scaffolding over the existing bus and installing most all of the new
horizontal bus by ceiling hangers prior to the outage. Then a shorter six day
outage would be required to install the vertical transition boxes at the
generator disconnects and B-Phase GSU bus.
• The new bus will has less risk as it will be seismically certified as a packaged
system that includes the horizontal and vertical bus sections and associated
and hanger and support system.
Timeline for the recommended Alternative 2.):
2020 Q4 Commit to multiyear equipment supply contract -no cost
2021 Q2 Receive Bus A -$200K
Q3 Install Bus A -$400K and place in-service
2022 Q2 Receive Bus B -$200K
Q3 Install Bus A-$400K and place in-service
The project estimate for this equipment and associates labor are reasonable based on
the vendor proposals from Eaton and Technibus.
Key Stakeholders are Hydro Managers, Hydro Schedulers, and Plant Operations.
This project is effected by the station service project and it is the driver of when this needs
to be done. Due to priorities and projects that are already in the works it is not able to be
sequenced until 2023. In order for this to work the station service project will have to be
reconfigured and staged so that we can do half of the service and then the other half of
the service. In conclusion the project time frame will be changed due to changes in the
station service project.
Business Case Justification Narrative Page 3 o/4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 77 of 170
Cabinet Gorge 15kV Bus Replacement
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge 15kV Bus
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: ______LJ__;;_;::~~-----Date: (/Ja/tli!7
Print Name: Glen Farmer
Title: Electrical Engineering Manager
Role: Business Case Owner
Signature: Date:
Print Name: AndyVickers
Title: Director GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
5 ··vERSION HISTORY
Version Implemented Revision Approved Approval Reason
By Date By Date
1.0 Dave Schwall 06/28/19 Glen Farmer 06/28/19 Initial version
Template Version: 03/07/2017
Business Case Justification Narrative Page 4 of 4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 78 of 170
Cabinet Gorge Automation
I GENERAL INFORMATION
Requested Spend Amount $2,941,000
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Gategory Project
lnvestment Driver Asset Condition
1.1 Steering Committee or Advisory Group lnformation
As generating plants are managed by the Generation, Production, and Substation
support group, they provide energy and other services used by Power Supply. The
steering committee for this project includes members from both groups: Director
Power Supply; Director GPSS; Manager Hydro Ops and Manager Project Delivery.
This team receives monthly project status updates but meets only in the event that
a decision is needed.
The projecUstakeholder team meets on a more regular basis (at least monthly) to
work on the project's scope and planning. The project/stakeholder team is
comprised of representatives from the various engineering groups (electrical,
controls, mechanical) and plant operations.
2 BUSINESS PROBLEM
This plant was designed for base load operation. Today, Cabinet Gorge is called on
to not only provide load, but to quickly change output in response to the variability of
wind generation, to adjust to changing customer loads, and other regulating
services needed to balance the system load requirements and assure transmission
reliability. The controls necessary to respond to these new demands include speed
controllers (governors), voltage controls (automatic voltage regulator a.k.a. AVR),
primary unit control system (i.e. PLC), and the protective relay system. ln addition
to reducing unplanned outages, these systems will provide the ability for Avista to
Business Case Justification Narrative Page 1 of7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 79 of 170
Cabinet Gorge Automation
maximize these services from within the pool of its own assets on behalf of its
customers rather than having to procure them from other providers.
As part of the designated "Regulating Hydro" class of assets.
The key metric for these plants is their Equivalent Availability
Factor or EAF.
Chart 1 - Equivalent Availability Factor
Equivalent
Availability Factor
(EAF) measures the
amount of time that
the Unit is able to
produce electricity
in a certain period,
divided by the
amount of time in
that period. In this
case, Cabinet
Gorge has
averaged below
85% EAF for the
twelve month rolling
period ending
September 2016.
The internal
company target for
this measure is
85o/o
Some of the outages that cause the EAF to fall below the target include forced and
maintenance outages associated with the control and protection systems described.
Some recent events captured are attached to this document for referencel.
An additional problem with the existing speed controls (governors) is the lack of
response in a system frequency event. The graph below shows a significant
frequency "excursion" (the dark blue line) and the response of the machines at
Noxon Rapids HED to this excursion. Those are the lines that move upward on the
top of the chart. The response of the Cabinet Units is shown in the lines in the
I See "l8 Maximo Work Orders related to CG Controls."
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Business Case Justification Narrative Page 2 of 7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 80 of 170
Cabinet Gorge Automation
middle of the chart should have bumped up like the Noxon, but instead were non-
responsive.
Chart 2 - Lack of Frequency Response
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A similar chart showing voltage control issues at Cabinet Gorge can be found in
Appendix A.
There are several NERC Reliability standards against which the existing equipment
performs at a sub-standard level. One of these standards involves frequency
response as describe above. The related NERC standards are attached to this
document along with some technical explanation if more information is needed.
Last, there have been several unit outages that were specifically taken to address
problems associated with the existing control and protection equipment. 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. More details of
these events are can be found in the attached "18 Maximo Work Orders related to
CG Controls" document.
Business Case Justification Narrative Page 3 of 7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 81 of 170
Cabi net Gorge Automation
3 PROPOSAL AND RECOMMENDED SOLUTION
Avista's Safe & Reliable lnfrastructure strategic initiative seeks to leverage
technology and innovative products and services offered to existing and new
customers. The work proposed for Cabinet Gorge will include equipment and
component replacement geared at increasing reliability and unit control/monitoring.
Customers benefit in that it will allow Avista to economically optimize an existing
asset to provide energy and other energy related products.
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 extended outage will provide an opportunity to address other issues including,
insulating the generator housing roof, cooling water upgrade, unit flow meter and
other items to improve overall reliability. The objective is to ensure system
compatibility with current standards and improve system reliability.
Do Nothing / Continue to Repair: While the generator is capable of producing
energy with existing systems, the present equipment does not provide the system
support abilities needed to meet today's requirements (see graph above). 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.
Replace Unit Control, Monitorinq, and Protection Systems: ln 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.
lnstallation of new controls and protection will also provide increased visibility into
the systems allowing better remote monitoring and troubleshooting. New systems
Option Capital Cost $tart Complete
Do nothing / Continue to Repair $0 ongorng ongorng
Replace Unit Control, Monitoring, and
Protection Systems
$2,136,194 12t2015 12t2018
Mechanical, Controls, Electrical upgrades
and Stator Re-wedging
$2,936,194 12t2015 12t2018
Business Case Justification Narrative Page 4 of 7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 82 of 170
Cabi net Gorge Automation
are also configured so compliance with NERC standards is much easier to achieve.
As this option addresses the primary issues, this is considered the minimal preferred
option.
Mechanical. Controls. Electrical norades and Stator Re-wedoino:This option is
the same as the Replace Unit Controls, Monitoring, and Protection Sysfems
described above except this also includes addressing additional items related to the
reliability of the generating unit. This may include replacing the insulation system
on the generator rotor, re-wedging the generator stator, replacing and updating
auxiliary system motor controls, and other items identified as necessary to both
extend the life of the asset and improve the reliability. This option would allow for
work that would be necessary in the near future to be performed now therefore
avoiding future outages and improving the near and long term reliability of the units.
While this is the preferred option, it cannot be selected at this time due to the gantry
crane's limitations2.
P ram Cash Flows
2 The gantry crane is needed to pick the rotor in order to perfotm the re-wedging work. The gantry crane is in
a state ofdisrepair which is being addressed by a separate business case.
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Business Case Justification Narrative Page 5 of 7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 83 of 170
Cabinet Gorge Automation
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Automation
Business Case and agree with the approach it presents and that it has been
approved by the steering committee or other governance body identified in Section
1.1. The undersigned also acknowledge that significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
rAAr-L Þ¿t/.
Business Case Owner
Date: Ztt+61¡y
Date
Template Version : 03107 12017
A¿o
erS
D ìrecfo. G Pg I
Business Case Sponsor
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Terri Echeooven 04t14t17 Steve Wenke 04t14t17 lnitialversion
Business Case Justification Narrative Page 6 of 7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 84 of 170
Cabinet Gorge Automation
APPENDIX A
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Business Case Justification Narrative PageT of7
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 85 of 170
Cabinet Gorge Gantry Crane Replacement
I GENERAL INFORMATION
1.1 Steering Gommittee or Advisory Group lnformation
Steering Committee members are comprised of: Director - GPSS, Manager,
Hydro Operations & Maintenance and Manager - Project Delivery. Steering
Committee members are provided a monthly project status report but, meet only in
the event a decision point is needed.
Other key stakeholders include: Manager, Clark Fork River Hydro; Manager,
Mechanical Engineering. Additional Cabinet Gorge Hydro Electrical Development
mechanical staff that more directly represent the interests of the plant itself are
consulted regularly.
2 BUSINESS PROBLEM
The gantry crane at Cabinet Gorge Hydro Electrical Development was used in the
original construction of the plant in 1952-53. The crane is rated at275 tons but can
perform lifts as heavy as 330 tons on an occasional basis given that a certified test
has been performed. As the asset has aged, various upgrades and updates have
been made to prolong the crane's usefulness. However, it has become apparent
that the crane is unable to perform the duties required of it in a dependable
manner.
The gantry crane is of the only means of moving the large machinery found at
Cabinet Gorge Hydro Electric Development such as moving/placing transformers,
tailgates and generators. lt is also the only way other equipment can be moved
into and out of the plant. lts inability to function reliably impacts the work that is
able to be performed at the plant and presents a safety risk to personnel if the
crane fails to control the load. There is also a risk of not being able to accomplish
repairs in the event of an emergency related to any one of the four generating
units. ln essence, the gantry crane is a bottle neck preventing both annual
maintenance work and capital improvements alike.
The crane has a long history of breakdowns and operational problems. Most
recently, during the Cabinet Gorge Unit #1 rehabilitation project spanning from
2014 to 2016, problems with the crane caused significant delays. Some examples
include:
Relay/Contactor control problem - approx. 6 days
Requested Spend Amount $3,530,000
Req uesting Organ ization/Department Generation Production and Substation Support
Business Gase Owner Jacob Reidt
Business Case Sponsors Andy Vickers
Sponsor Organ ization/Department Generation Production and Substation Support
Category Project
lnvestment Driver Asset Condition
Business Case Justification Narrative Page 1 of8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 86 of 170
Cabinet Gorge Gan Crane Replacement
Gear/bearing problem - approx. 3 weeks
Brake problem - approx. 2 days
Additional problems experienced with the crane during the Unit #1 rehabilitation
are documented in a memo by Ryan Bean, dated November 13,2015, attached as
Appendix A below.
lnspections performed by Professional Crane lnspections in the years 2010,2012,
2015 and 2016 each give the crane an overall condition level 3 indicating that
"Minor to moderate performance issues exist. PCI recommends repair or
adjustment as soon as practical." Copies of these inspection reports can be made
available upon request. A summarized list of foreman reports dating back to 1966
can be found in Appendix B below.
The successful outcome of this project would be to deliver a state-of-the-art crane
capable of safely and reliably providing rated lifting capabilities for the likes of draft
tube bulkheads, Generation Step-Up transformers and any one of the four
generators.
A properly functioning crane at Cabinet Gorge Hydro Electric Development
enables Avista to tend to the aging assets and maintenance needs of plant
machinery to ensure that they run safely and reliably.
Customers benefit in the ability to adequately and safely maintain this equipment
to continue to provide low cost and reliable energy.
3 PROPOSAL AND RECOMMENDED SOLUTION
Do Nothinq: doing nothing is an option however, given the criticality of this asset,
doing nothing would leave the plant at risk should an emergency arise
necessitating the crane's use
Alternative #1: Full Replacement. Advantages of this option include new structure
designed and rated for 330T from conception, modernized controls utilizing current
technology, reduced maintenance costs, elimination of as-building the existing
crane structure, full archived drawing and product data set and removal of any
lead-based paint and asbestos contamination risks.
Alternative #2: Replacement w/Extended Reach. This alternative expands on
alternative #1 by utilizing extended reach to enable reach to the transformers and
leg pass-through design enabling access to the draft tube bulkheads.
Replacement with extended reach represents a modest increase (comparatively)
Option Estlmated
Gapltal Cost
$tart Complete
Do nothing $o
Alternative 1: Full Replacement $5,308,449 03t2017 12t2018
Alternative 2: Replacement Mextended
reach
$7,272,000 03t2017 12t2018
Alternative 3: Refurbishment $3,894,173 03t2017 12t2018
Business Case Justification Narrative Page 2 of 8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 87 of 170
Cabinet Gorge Gantry Crane Replacement
in price but will provide savings in terms of usability for the foreseeable future in
terms of lifting capability. The estimated capital cost of $7,272,000 represents a
very high level estimate at this point.
Alternative #3: Refurbishment. Advantages of refurbishment included lower up-
front costs resulting from retaining the majority of the steel structure and a reduced
level of demolition and installation work. However, this alternative would require
lead-based paint and asbestos abatement and without X-ray examination of each
rivet, it would be impossible to accurately and definitively assess the true condition
of the structure.
A final decision has yet been made with regard to selection of Alternatives 1,2, or
3. However, with any option we anticipate construction will take upwards of four
months, following dismantling of the existing crane. Due to weather conditions
inherent in north ldaho, it would be optimal to construct the new crane during the
months of June to September. Given the long lead time expected in the
manufacturing of a new crane (upwards of twelve months), we anticipate that all
construction will be completed and the project placed in service no later than
December 31,2018.
Business Case Justification Narrative Page 3 of 8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 88 of 170
Cabinet Gorge Gan Crane Replacement
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Gantry Crane
Replacement Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
4,/
[) irerÞ. GP eç
Mcn cÐMñL,t¿ß & Prùt
Date: bf ?Oy¡7
Date
Tem plate Version : 03107 12017
er- 9
Business Case Sponsor
VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Terri Echegoyen 4t14t2017 Steve Wenke 4t14t2017 lnitial version
Business Case Justification Narrative Page 4 of 8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 89 of 170
Cabinet Gorge Gantry Crane Replacement
APPENDIX A
DATE: NOVEMBER 13TH, 2015
TO: FILE, JACOB REIDT, RANDY PEIRCE, BOB WEISBECK, MIKE SHOFF
FROM: RYAN BEAN
SUBJECT: CABINET GORGE UNIT 1 - GANTRY CRANE ROTOR PICK
PROBLEMS
Backsround
The scope of work during the Unit 1 rehabilitation included two picks of the generator rotor
complete with field poles installed. The first pick removed the rotor from the stator and placed it
in the shop for field pole removal. The rotor was then moved to the rotor storage building until
the field poles were returned after being refurbished by RPR Hydro (subcontractor to GE). The
field poles were reinstalled in the rotor storage building and the rotor was then placed back in the
stator.
An Engineered Pick Plan was produced in accordance with ASME Code Section 830.2-3.I.7 thaf
allows for occasional picks for loads exceeding rated limits up to 125o/o of the nameplate rating.
The crane nameplate is275 tons with an occasional pick of up to 343.8 tons. The rotor with lifting
device weighs approx 330 tons. The cranes ability to lift this load was confirmed by Bedford
Crane during the initial installation. The code allows an occasional pick not to exceed two
occurrences in a 12 month period provided the crane manufacturer or other qualified person has
reviewed the crane design to handle the load.
Inconsistencies During Operation
During the initial removal of the rotor from the stator, the micro drive and main hoist motor were
used. The micro drive operated as expected, however the main hoist motor appeared to struggle
when initially engaged. While returning the rotor to the stator on September 22nd,2015, an issue
was experienced where the main hoist did not operate as expected during raising. This was a
repeatability issue with the main hoist where the hoist may raise, stall, or lower the rotor when the
control lever was taken back into the same notch repeatedly. The lift was stopped and an
investigation followed.
Investisation and Troubleshooting
V/ith assistance from PCI and K&N Electric, an investigation and troubleshooting of the power
and control systems followed. Components checked included the control lever, overloads,
contactors, resistors, motor currents, brakes, and micro-drive operation. Everything appeared to
be operating correctly, albeit in an overloaded condition due to the above nameplate load. The
micro-drive operated reliably throughout testing. This lead us to believe the problem resides
downstream of the control system, potentially with either the motor output or mechanical drive
system. The gear train was visually inspected via available access ports and appeared to be in
good shape and operated smoothly.
Original records of the hoist motor test data indicate the existing hoist motor reaches its nameplate
current of 160 amps at a load of approximately 205 tons. This limits the service cycle at 240 amps
with a load of approx. 320 amps to approximately one to two minutes without overheating resistor
banks. This would require several lifting and cooling offperiods to complete the lift. This reflects
Business Case Justification Narrative Page 5 of 8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 90 of 170
Cabinet Gorge Gantry Crane Replacement
what we experienced in the field with tripping of the overload relays during sustained lifting at
approx. 250 amps.
The crane micro-drive arrangement was also inspected, which consists of an additional motor and
speed reducer that can be clutched in or out as necessary. The arrangement utilizes the same main
hoist drivetrain and brakes (with an additional motor brake) without using the main hoist motor.
Per Mark Oney's crane evaluation dated May 10, 1994 and design drawings, the micro-drive is
rated for continuous duty without overheating. Hoisting speed is reduced during operation to
slightly less than 0.5 feet per minute.
Conclusion
This has historically been a difficult pick for this crane and the system appears to have reached an
impasse where the main hoist is no longer capable of producing the power to function at l00Yo.'We suspect the issue lies in either the motor output, which has been operated above its nameplate
current a number of times in the past, or due to an increase in mechanical drag in the gear train.
Per the results of our initial investigation and a stakeholder meeting on October 5fh,2015, (Ryan
Bean, Andy Vickers, Mike Gonnella, Bob Weisbeck, Brand McNamara, Rob Selby, and Jeremy
Winkle in attendance) and in agreement with the project Foreman Mike Shoff, the rotor pick was
completed using the installed micro-drive system, without the use of the main hoist motor.
References
L. CG 1 Rotor Pick Plan Oct 201-5 Revl-
2. ASME Crane code for CGL
3. Crane Report by Mark Oney, May 10 9944. D-1570Ls00Ict952 - Gantry Clearance Diagram with notes
5. 3O4E-25-O40-0L-01, 02, 03,04, 05,08 - Micro Drive Arrangement Drawings
6. 1952 Load Test Data
7. 1993 Load Test Data
Business Case Justification Narrative Page 6 of 8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 91 of 170
Cabinet Gorge Gantry Crane Replacement
APPENDIX B: SUMMARIZED FOREMAN REPORTS
Job Title Begin
date End date Description
Gantry Crane -
Mechanical
Maintenance
5t2311966 7t1t1966
Replaced sheaves and greased bearings
on large hook. Applied oil to bearings on
trolley. Drained and cleaned gear cases.
Checked brakes.
Repair Gantry Crane 3t31t1969 4t9t1969
Large bevel gear was removed. New
bushing was installed and the drive
reassembled. Wheel guards were
repaired and installed.
Re-reeve Gantry
Crane Main Hook -
Cabinet Gorge
Station
12t2t1976 12t14t1976 Old cable was removed and new cable
added to the drums.
Crane Maintenance 11t14t1988 11t14t1988 Main hoist gear box inspected. Friction
brake assembly was seized together.
Redo Crane Track
Splices 4t5t1993 5t13t1993 Weld holding rails together were
repaired.
Gantry Crane -
Bridge Drive Motor 1t23t1997 2t11t1997
The bridge drive motor on the Gantry
Crane was removed and sent in for
repair. Report includes repair details.
Crane Maintenance 6t28t1999 7t29t1999
The bridge motor, brake and gearbox
were inspected. Trolley motor removed
and sent to K&N for maintenance.
Annual Safety
lnspection for Gantry
Crane
7t12t2000 7t12t2000 Mechanical and Electrical inspection of
crane components.
Crane Maintenance 5t1t2000 7t13t2000
Crane was pressure washed. Full
structural inspection completed. Rusting
areas noted. The main and auxiliary
hoists were load tested.
Gantry Crane
Maintenance "03"6t16t2003 8t26t2003
Replaced all races and several bearings,
and repaired sheaves of the main hoist
block. Replumbed bridge brake system
and repaired/replaced several brake
components. Maintained the trolley
controller (electricians), main and
auxiliary hoist cables, and open
Business Case Justification Narrative Page 7 of I
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 92 of 170
Cabinet Gorge Gantry Crane Replacement
Job Title Begin
date End date Description
275Ton Gantry
Crane Load Test 6t5t2006 6t8t2006
Components of the main hoist had been
modified necessitating a load test
(Repod from load test on the 275 ton
gantry cane).
Crane Maintenance
2010 9115t2010 9t15t2010 Abbreviated maintenance on the gantry
crane. See report for details.
Gantry Crane Oil
Analysis 4119t2011 4t19t2011 OilAnalysis results for Gantry Crane
components.
Gantry Crane
Maintenance 2Q11 4t11t2011 4t20t2011
Report includes details on maintenance
of the gantry crane, checklist included.
Report state the crane in in dire need of
a paint iob.
Annual Maintenance
Gantry Crane 4t9t2012 5t3t2012 Crane condition regarding many items is
not satisfactory, see report for details
detailed Foreman repofts can be found here > c01m1 14lG:llForemanreports.accdb
sååt
Business Case Justification Narrative Page 8 of 8
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 93 of 170
Colstrip 3&4 Capital Projects
Business Case Justification Narrative Page 1 of 4
EXECUTIVE SUMMARY
This Business Case request is for Colstrip 3&4 capital projects. Avista does not operate the facility nor does
it prepare the annual capital budget plan. The current operator provides the annual business plan and capital
budgets to the owner group every September. They also provide individual project summaries which
characterize the work using categories similar in concept the Avista business case drivers. Avista reviews
these individual projects. Some of them are reclassified to O&M if the work does not conform to our own
capitalization policy. Avista does not have a “line item veto” capability for individual projects although
individual projects can be cancelled or postponed if a sufficient majority of the owners agree.
Generally, by the subsequent November meeting, the business plan is approved in accordance with the
Ownership and Operation Agreement for units 3&4 that six companies are party to. The amount requested
in this Business case is generally an estimate taken from the prior year’s forecast. As a result, the final
approved Colstrip capital budget may not exactly match the amount highlighted in this Business Case.

VERSION HISTORY
Version Author Description Date Notes
1.0 Thomas Dempsey Summary 7/19/2020 New BC Format

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 94 of 170
Colstrip 3&4 Capital Projects
Business Case Justification Narrative Page 2 of 4
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
This is a program business case that covers Avista’s share of Colstrip 3&4 capital projects. These include any and all capital associated with ongoing operation of the facility.
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
All of the identified areas apply as this Business Case covers all capital expenditures at Colstrip. Although Avista does not as a 15% owner generally have the ability to approve or disapprove of specific projects, each project is considered on its merits and
drives Avista’s decision to approve or disapprove of the overall budget.
1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
This question is not applicable for this Colstrip program Business Case as this is a placeholder for any and all capital expenditures at Colstrip. The risks are specifically evaluated on a project by project basis.
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.
Certain types of capital projects include the calculation of internal rate of return as a metric. Others are required by regulation. Others are driven by safety considerations.

1.5 Supplemental Information
Each year Talen provides capital justification forms for each capital project with metrics identified if applicable. Where needed, Avista may perform its own financial analysis of a specific project being proposed.
Requested Spend Amount Varies by year
Requested Spend Time Period Ongoing
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Thomas C Dempsey | Andy Vickers
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver N/A
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 95 of 170
Colstrip 3&4 Capital Projects
Business Case Justification Narrative Page 3 of 4

3.1 Steering Committee or Advisory Group Information
Avista is a 15% owner of Colstrip units 3&4 and votes its ownership share. The plant level steering committee for budget approval includes Avista, Puget, PGE, Pacificorp, Talen, and PacifiCorp. Owners do not have a line item veto for individual capital projects but can vote down the overall budget if a sufficient
majority exists.
3.2 Provide and discuss the governance processes and people that will provide oversight
Oversight is provided by Avista’s plant representative, the Manager of Thermal Operations, and the Director of Generation Production Substation Support.
Budget review and approval is given by the Senior VP of Energy Resources.
3.3 How will decision-making, prioritization, and change requests be documented and monitored
Day to day management of the facility is handled by Talen as agent for all of the owners. By contract they are obliged to perform in accordance with prudent
utility practice. Budget and project review is performed regularly and presented to all of the ownership during a monthly or semimonthly Ownership & Operation Committee meetings.
The undersigned acknowledge they have reviewed the Colstrip 3&4 Capital Projects
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: 08/04/2020
Print Name: Thomas C Dempsey
Title: Mgr. Thermal Operations & Maintenance
Role: Business Case Owner

Signature:

Date: 08/04/2020
Print Name: Andy Vickers
Title: Director GPSS
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 96 of 170
Colstrip 3&4 Capital Projects
Business Case Justification Narrative Page 4 of 4
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 97 of 170
Generation DC Supplied System Update
Business Case Justification Narrative 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. With NERC requirements followed and design enhancements the DC system is being
monitored, tested and remains reliable. Experience shows that we must continually monitor,
review and maintain our DC system. The equipment manufactures gives an estimated life span to
the batteries and auxiliary equipment. Some of these estimates have not hit the mark and have been
changed out early due to failing tests or issues with the equipment. Proven manufactures are used
to improve reliability and life. The risk of not approving this program would reduce the reliability
of our generation and control facilities.

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

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 98 of 170
Generation DC Supplied System Update
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?
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
Year Current Approval Requested Change Proposed Total
2021 $840,000 $0 $840,000
2022 $900,000 $0 $900,000
2023 $840,000 $0 $840,000
2024 $900,000 $0 $900,000
2025 $0 $800,000 $800,000
Requested Spend Time Period yearly
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Glen Farmer | Andy Vickers
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 99 of 170
Generation DC Supplied System Update
Business Case Justification Narrative Page 3 of 7
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. In order 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 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:
1. Comply with NERC requirements for inspection and testing.
2. Address battery room environmental conditions to optimize battery life.
3. Replace any legacy UPS systems with an invertor system.
4. Address auxiliary equipment based on life cycle.
5. Hydrogen sensing and fire alarm, eyewash station and lighting.
6. Wall separation of batteries and auxiliary equipment.
7. Install Programmable logic controller monitoring and new operating screens to
provide visibility for operations and maintenance purposes.
8. Provide new distribution panels, disconnect switches, voltage conversion devices
for communications equipment that operate at different voltages.
9. Establish current drawings, construction documents, I/O list, plans, schedules,
manuals and as-builts.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 100 of 170
Generation DC Supplied System Update
Business Case Justification Narrative Page 4 of 7

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.
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.

Option Capital Cost Start Complete
1. Address the DC systems as they fail testing or battery issues arise. $1,315,000/yr 01/2017 12/2030
2. Establish an independent DC system
replacement program to bring plants to a
standard as quickly as possible.
$1,315,000/yr 05/2027 8/2026

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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 101 of 170
Generation DC Supplied System Update
Business Case Justification Narrative 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.
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. spend, and transfers to plant by year.
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

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 102 of 170
Generation DC Supplied System Update
Business Case Justification Narrative Page 6 of 7
2.8.1 Identify customers and stakeholders that interface with the business case
Electric shop, Relay shop, Engineering, Operations, Protection, Environmental, Project Management and Power Supply.
2.8.2 Identify any related Business Cases
None
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 How will decision-making, prioritization, and change requests be documented and monitored.
Persons providing oversight include: Generation Electrical Engineering Manager, Forman PCM shop, Manager C&M - Electric Shop and the Plant
Managers.

The undersigned acknowledge they have reviewed the Generation DC Supplied
System Update 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: Glen Farmer
Title: Generation Electrical Engineering Manager
Role: Business Case Owner

Signature: Date:
Print Name: Andy Vickers
Title: Director, GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name: Bob Weisbeck
Glen S. Farmer 8/1/2020
8/3/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 103 of 170
Generation DC Supplied System Update
Business Case Justification Narrative Page 7 of 7
Title: Manager, Hydro Operations and Maintenance
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 104 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

The Little Falls Plant Upgrade Program began in 2012 and in 2020, is in the final phases of implementation. With three project components left (Plant Sump, Drain Field, and Panel Room Roof/Enclosure for the new
controls equipment) the vast majority of the project scope has been completed and risks mitigated. The
remaining work has very little risk exposure and minimal impact on the plant’s current operations. Driven initially by the age of the infrastructure at the plant, Alternative 3, a full replacement of all four
generatring units and all obsolete supporting equipment, was selected, implemented, and put in service. Given as how the program is nearly complete and decisions have already been made in regards to the following, no additional details regarding solution recommendations, risk of failure to implement, schedule significance or benefit to customers are provided at this time.
The remaining programmed work is being scheduled into 2021 as a response to internal resource constraints, and therefore, this business case and its remaining activities are subject to this Business Case Refresh exercise.

VERSION HISTORY
Version Author Description Date Notes
1.0 Brian Vandenburg Initial draft of original business case 2.14.17 Signed/approved
1.1 Kara Heatherly Conversion to new format 6.20.20 Includes budget update

GENERAL INFORMATION
Requested Spend Amount $56,100,000
Requested Spend Time Period 10 years
Requesting Organization/Department GPSS
Business Case Owner | Sponsor Brian Vandenburg | Andy Vickers
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 105 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 2 of 7
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The existing Little Falls equipment ranges in age from 60 to more than 100 years old. Little Falls
experienced an increase in forced outages over the past six years, increasing from about 20 hours in 2004 to several hundred hours in the past several years, due to equipment failures on a number of different pieces of equipment.
Once the business case is complete, a study of forced outages at the plant over a 5 year period could
be taken and measured against the pre-construction outage numbers to determine if plant availability has increased and the business case objective met.
1.2 Discuss the major drivers of the business case and the benefits to the customer
The major drivers for the Little Falls Plant Upgrade are available and reliability. See the graph below
that illustrates the trend line for availability at Little Falls.

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred
See alternatives analysis narrative conducted at project onset in section 2.1 for additional details.
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.
See alternatives analysis narrative conducted at project onset in section 2.1 for additional details.

Option Capital Cost O&M Cost Start Complete
0.8
0.85
0.9
0.95
1
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Plant Availability
Trend Line
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 106 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 3 of 7
Alternative 3: Preferred $56,100,000 $0 2012 2021
Status Quo $0 $150,000/yr
Alternative 1 $5,000,000 $20,000/yr
Alternative 2 $83,000,000 $0
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Summary of alternatives:
Status Quo: Forced outages and emergency repairs would continue to increase, reducing the reliability of the plant. Each time a generator goes down for an emergency repair, Avista is forced to
replace this energy from the open market which leads to higher energy costs.
It is expected that the O&M costs would continue to climb as more failures occurred. This may also require personnel to be placed back in the plant to man the plant 24/7 in order to respond to failures. Again, increasing expenses for the project with no benefit in performance.
Alternative 1: Replace Switchgear and Exciter: This would replace the two items that are currently responsible for the majority of the forced outages, and then continue to use the remaining equipment.
This alternative is a temporary fix. One of the generators has a splice and is expected to fail in the next few years. If this generator fails before a new generator is ordered, this generator will be out of
service for 2 years. The control system is a vintage system and is on the verge of a total failure and spare parts are not available (a few minor system failures occurred in the past 2 years). If a total system failure is encountered, it is expected the plant to be down for a year as the control system is
designed, procured and installed.
Alternative 2: Replace all generating units with larger, vertical units capable of additional output.
Avista’s Power Supply group evaluated the present value of larger, vertical units at Little Falls. The increase in present value from larger units was $20M over a 30 year analysis. The capital
construction cost increase from in-kind replacement to vertical units was $27M.
This present value calculation of benefit did not include risk. Installing new vertical units would require modification of the powerhouse foundation and presents serious construction risk. Due to the high construction costs, high risk, and low payoff NPV, this alternative was abandoned.
Alternative 3 and Proposed Alternative: Replace nearly all of the older and less reliable equipment with new equipment. This includes replacing two of the turbines, all four generators, all generator breakers, three of the four governors, all of the AVR's, removing all four generator exciters, replacing the unit controls, replacing the unit protection system, and replacing and modernizing the station service. All major equipment would be procured through a competitive bid process to help keep construction costs low. Equipment would also be purchased for all four units at once to help keep costs down.
Additional Justification for Proposed Alternative:
Because of the age and condition of all of the equipment at the plant, all of the equipment has been qualified as obsolete in accordance with the obsolescence criteria tool. The Asset Management tool has been applied to Little Falls and also supports this project. The Asset Management studies that have been done to date are still subject to further refinements, but the general conclusions support
this project. There are many items in this 100 year old facility which do not meet modern design standards, codes, and expectations. This project will bring Little Falls to a place where it can be relied on for another 50 to 100 years. Finally, this project will need to be worked in coordination with our Indian Relations group as the Little Falls project is part of a settlement agreement with the Spokane Tribe.
Strategic Alignment:
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 107 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 4 of 7
The Little Falls 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.
2.2 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.
In accordance with the detailed project schedule, annual projected capital expenditures for remaining scope are in accordance with the 5-year CPG budget table below.

2.3 Outline any business functions and processes that may be impacted (and how) by the business case for it to be successfully implemented.
No direct relationship exists between the other parts of the business and the completion of the remaining Little Falls program work. All integral connection points with other business units have already been made. Equipment upgrades have been performed to support other corporate priorities (such as EIM and HMI) and plant processes that are impacted by the remaining work
are directly and appropriately involved in the planning and scheduling of that work in order to insure seemless integration with the plant.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
See alternatives analysis narrative conducted at project onset in section 2.1 for additional details. This project is in the closeout phase and budget is being adjusted into future years to respond to resource availability. Any remaining project risks will be mitigated at the project steering committee level for the remaining active program components.

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.
Milestone Schedule (reflective of original business case milestones):
January 2010 Program Begins
Year Requested Amount CPG Approved Amount
(Admin use only)
2021 $800,000
2022 $0
2023 $0
2024 $0
2025 $0
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 108 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 5 of 7
March 2012 Exciter & Generator Breaker Replacement Complete
January 2014 Warehouse Construction Complete
January 2014 Bridge Crane Overhaul Complete
February 2015 Station Service Replacement Complete
February 2016 Unit 3 Modernization Complete
April 2017 Unit 1 Modernization Complete
October 2017 Backup Generator Install Complete
May 2018 Unit 2 Modernization Complete
May 2019 Unit 4 Modernization Complete
October 2019 Headgate Replacement Complete
Yearly Transfer to Plant:
2013 $3,100,000
2014 $2,000,000
2015 $4,000,000
2016 $16,300,000
2017 $10,400,000
2018 $9,000,000
2019 $13,000,000
Total $57,800,000

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 our exposure to potential, prolonged breaks in service.
Strategic Initiatives: 1. Safe and Reliable Infastructure, 2. Responsible Resources.
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 considers not only the likelihood of risk but the severity of the outcome in the event of failure. Prior to their upgrade, failure of these sytems could have been nearly immediately catastrophic. Minimizing the severity of non-preventable failure is the prudent and
responsible thing to do.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Customers and Stakeholders:
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 109 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 6 of 7
Mike Magruder Manager, Hydro Operations and Maintenance
Alexis Alexander Manager, Spokane River Hydro Operations
Kevin Powell Chief Operator, Long Lake and Little Falls HED
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.
3.2 Provide and discuss the governance processes and people that will provide oversight
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 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 any 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.
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.
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 Project/Program Steering Committee when and if determined to be necessary by the definitions above. 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.
The undersigned acknowledge they have reviewed the HMI Control Software 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: Brian Vandenburg
Title: Manager, Hydro Operations
Role: Business Case Owner

Signature: Date:
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Jul-10-2020 | 8:14 AM PDT
Jul-10-2020 | 8:30 AM PDT
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 110 of 170
Little Falls Plant Upgrade
Business Case Justification Narrative Page 7 of 7
Print Name: Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor

Signature: Date:
Print Name: Scott Kinney
Title: Director of Power Supply
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
DocuSign Envelope ID: 84285D87-DDB0-4022-A678-14C386E1992D
Jul-13-2020 | 5:56 AM PDT
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 111 of 170
Business Case Justification Narrative Page 1 of 7
Long Lake Plant Upgrade Program

EXECUTIVE SUMMARY

The existing Long Lake 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 six years, almost zero in 2011
and increasing every year since then. This is caused by equipment failures on a number of different
pieces of equipment. 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 $60.5M has been developed from a Class 4 Estimate.

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 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.

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. 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.

With the increase in generator output, the output of the generator step up transformer (GSU) has also
increased to its rating. 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 drivers for the program is Station Service disconnect
switching safety.

VERSION HISTORY
Version Author Description Date Notes
1.0 Brian Vandenburg Initial approved original business case 3/22/2017 Signed 4/19/17
1.1 Michael Truex Updated Business Case 6/19/2020 Updated with BC Refresh
1.2 Michael Truex Updated BC with greater detail 7/31/2020 Added content

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 112 of 170
Business Case Justification Narrative Page 2 of 7
Long Lake Plant Upgrade Program

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The existing Long Lake 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 six years, almost
zero in 2011 and increasing every year since then. This is caused by equipment failures on a
number of 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 of 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.
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 generator step up transformer (GSU)
has also increased to its rating. These GSU's are now running at the high 65C temperature
Requested Spend Amount $60,500,000
Requested Spend Time Period 2009 - 2026
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner | Sponsor Brian Vandenburg | Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 113 of 170
Business Case Justification Narrative Page 3 of 7
Long Lake Plant Upgrade Program

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
The Long Lake Plant Upgrade addresses multiple drivers; Service Quality & Reliability, Performance & Capacity, aged assets, and failing plant with operational impacts. It is important for our customers that our generating units are both available and reliable. It is also prudent that Avista maintain personnel safety for employees working at the plant.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 114 of 170
Business Case Justification Narrative Page 4 of 7
Long Lake Plant Upgrade Program

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
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.
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.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 115 of 170
Business Case Justification Narrative Page 5 of 7
Long Lake Plant Upgrade Program

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 116 of 170
Long Lake Plant Upgrade

Business Case Justification Narrative Page 6 of 11

Alternative 4 and Recommended Alternative: Replace Units In-Kind would replace the
existing major unit equipment (generator, field poles, governors, exciters, generator
breakers) with new equipment.
Option Capital Cost Start Complete
Alternative 1: Install four new 30MW vertical units $173M 05 2018 06 2030
Alternative 2: Construct one unit powerhouse $144M 05 2018 06 2035
Alternative 3: Construct two unit powerhouse $276M 05 2018 06 2035
Alternative 4 and Recommended Alternative:
Replace units in-kind
$60.5M 05 2018 03 2027
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 as a result 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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 117 of 170
Long Lake Plant Upgrade

Business Case Justification Narrative Page 7 of 11

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.
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 Kaplin 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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 118 of 170
Long Lake Plant Upgrade

Business Case Justification Narrative Page 8 of 11

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. Within this option, there
are 10 options regarding GSU configuration, Bus configuration, and Generator Voltage.

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.
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
December 2021 - Station Service Replacement Commissioned
January 2023 – PLC Sump Upgrade
October 2023 – GSU Upgrade Phase 1
December 2023 – First Unit Upgrade
December 2024 – Second Unit Upgrade
October 2025 – GSU Upgrade Phase 2
December 2025 – Third Unit Upgrade
February 2026 – Facilities Upgrade Phase 2
December 2026 – 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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 119 of 170
Long Lake Plant Upgrade

Business Case Justification Narrative Page 9 of 11

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
 Program Steering Committee:
o Andy Vickers – GPSS Director
o Bruce Howard – Sr. Director Environmental Affairs
o Scott Kinney – Director Power Supply
 Respective Project Steering Committee Members:
o Jacob Reidt – Project Delivery Manager
o Bob Weisbeck – Manager Hydro Operations & Maintenance
o Alexis Alexander – Manager Maintenance Management & Construction
o Meghan Lunney – Manager Spokane River License
 Project Sponsor: Andy Vickers – GPSS Director
 Budget Owner: Brian Vandenburg – Lower Spokane River Manager
 Program Manager: Michael Truex – Long Lake Program Manager
 Project Manager: Various
 Internal Project Stakeholders:
o Asset Management: Robert Gray (Sr Eng II)
o AVA Construction: Brad McNamara (Electric Shop GF), Jeff Vogel (Relay Shop
GF), Randy Pierce (Mechanic Shop GF)
o Engineering Roundtable: Lamont Miles (Sr Engineering I-Project Manager)
o Enterprise Assets: Jennifer Lund (Manager)
o External Communications: Jae Ham (Comm Spec II)
o GPSS Engineering Managers: PJ Henscheid (Civil), PJ Henscheid (Mechanical),
Kristina Newhouse (Controls), Glen Farmer (Electrical)
o GPSS Engineers: Eric Atkinson (Electric Contractor Crew Inspector)
o Hydro Compliance: Michelle Drake (Supervisor Hydro Compliance)
o Power Supply: Pat Maher (Sr Hydro Op Eng II), Steve Lentini (Sr Hydro Op Eng
II)
o Project Management: Michael Lang (Product Owner)
o Program & Project Delivery: Elizabeth Arnold (IT Program Manager)
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 120 of 170
Long Lake Plant Upgrade

Business Case Justification Narrative Page 10 of 11

o Relay & Protection Design: Randy Spacek (Mgr Engineering Protection), Kevin
Damron (Sr Eng I)
o Safety & Craft Training: Clint Sharp (Safety and Health Specialist)
o SCADA: Garth Brandon (Chief Systems Operator)
o Spokane River - Hydro: Brian Vandeburg (Lower Spokane River Mgr), Kevin
Powell (Long Lake Chief Operator), Craig Bourassa (Sr Plant Engineer)
o Spokane River License: Meghan Lunney (Mgr Spokane River License), Robin
Bekkedahl (Sr Enviro Scientist), Rene' Wiley (Env Spec Scientist III)
o Substation Design: Glenn Madden (Mgr Engr Substations)
o Supply Chain Management: Cody Krogh (Mgr Supply Chain), Karen Carter (Sr
Sourcing Professional), Shelly Campbell (Sr Sourcing Professional)
o Transmission Design: Mike Magruder (Director T&D System Ops,
Transmission), Ken Sweigart (Mgr Engr)
o Utility Accounting: Bill Abrahamse (Sr Unitization Accountant)
 Core Project Team:
o Avista Engineering: Tracy West (Mechanical), Rob Selby (Electrical), Paul
Lennemann (Civil), Jeremy Fauth (Controls), Nick Agostinelli (Mechanical)
o Avista Construction Foremen: Jeremy Hostetler (Electrical), Chuck Parker
(Mechanical), TBD (Relay)

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.
3.2 Provide and discuss the governance processes and people that will provide oversight
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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 121 of 170
Long Lake Plant Upgrade

Business Case Justification Narrative Page 11 of 11

Each respective project within the LLPU will have additional steering committees and
meet at their own cadence.
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 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.

The undersigned acknowledge they have reviewed the Long Lake Plant 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.

Business Case Owner

Business Case Sponsor

Template Version: 05/28/2020
7/31/2020
7/31/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 122 of 170
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

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 123 of 170
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 $16,800,000
Requested Spend Time Period 5 years
Requesting Organization/Department L07, D07, I07 / GPSS
Business Case Owner | Sponsor Bob Weisbeck | Andy Vickers
Sponsor Organization/Department A07 / GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 124 of 170
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 $16,800,000 01/2021 12/2025
Individual Capital Projects $16,800,000 01/2021 12/2025
Perform O&M maintenance 0
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 125 of 170
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 $3.5 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 $3.5 million. In order support the budget constraints of the
department, this amount has been reduced by 10% for 2021 and 2022. 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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 126 of 170
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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 127 of 170
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 $3.5
Million. In order to support the capital budget goals of the GPSS department, this
budget was reduced in the short term for 2021 and 2022 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 (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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 128 of 170
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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 129 of 170
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
7-2-2020
Bob Weisbeck
Manager, Hydro Ops and Maint
7/2/2020
Director GPSS
Andrew Vickers
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 130 of 170
Cabinet Gorge Unit 3 Protection & Control Upgrade
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. 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 protection and
controls equipment. This equipment includes speed controllers (governors), voltage
controls (automatic voltage regulation a.k.a. AVR), primary unit control systems (Programmable Logic Controllers) and the protective relay system all of which serve to increase communications and reaction time. Timing for this work is not unrelated to
Avista’s entrance into the Energy Imbalance Market (EIM). The risks for not completing
these upgrades include an inability to quickly respond to market demands thereby
jeopardizing Avista’s ability to serve its customers.

VERSION HISTORY
Version Author Description Date Notes
Draft Glen Farmer Initial draft of original business case 8/1/2020

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 131 of 170
Cabinet Gorge Unit 3 Protection & Control Upgrade
Business Case Justification Narrative Page 2 of 6

GENERAL INFORMATION

1. BUSINESS PROBLEM
[
1.1 What is the current or potential problem that is being addressed?
The problem being addressed is the protection and control systems on Cabinet Gorge Unit 3. These systems have reached end of life and serve to provide start, stop, run, change load, react to system changes and protect the generator from
electrical disturbances.
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 protection and controls systems were installed in the early 1990’s. These systems can no longer be maintained due to the manufacturer no longer supporting the equipment. The customer benefits through higher reliability of Unit controls: i.e. reduced unexpected outages and manufacturer support of
upgraded equipment.

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred.
This is an overall protection and control upgrade that addresses all of the
components of the generator and turbine thereby ensuring that each auxiliary system connects and communicates as one. If individual failures were realized, they would be addressed with a patchwork of components that would not connect and communicate with one another. At some point in time, we would be
forced to rework the systems as a whole.

Requested Spend Amount
Requesting Organization/Department
Business Case Owner | Sponsor
Sponsor Organization/Department
Phase
Category
Driver
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 132 of 170
Cabinet Gorge Unit 3 Protection & Control 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.
This protection and control upgrade mirrors thirteen previous upgrades at
various plants throughout Avista’s generating facilitates. It provides consistency
on the auxiliary systems for maintenance and troubleshooting. Reduced reliance on manufacturer support decreases overall maintenance costs for auxiliary equipment. Interchangeability of the equipment and knowledge transfer amongst electricians, mechanics, technicians and engineering plays a key role
in reliability.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
No studies per se have been performed however, lessons learned from the previous thirteen upgrades have been incorporated into this design.

Option Capital Cost Start Complete
Replace Unit Control, Monitoring and Protection
System [CURRENT PLAN]
$750,000 01/2021 04/2021
Replace Unit Control, Monitoring and Protection
System, Reinsulate Pole Pieces and Stator Re-
wedge [ALTERNATIVE PLAN]
$1,750,000 01/2021 07/2021
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
Capital planning for this work consisted of bids from manufacturers to determine
best cost and schedule. Consistent communication platform between auxiliary
equipment was used to determine best compatibility. Information from previous projects was used to determine installation costs and schedules.

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.
Installation and commissioning of purchased equipment will take place in 2021. Maintenance costs will not be reduced but, Unit reliability will be improved
through decreased outages.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 133 of 170
Cabinet Gorge Unit 3 Protection & Control 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.
Design processes, purchasing processes, PI (IO to data historian) will be impacted, new control screens (HMI) for checkout and upgraded protection
enables the protection group to have direct communication with the relays.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
With regard to rebuilding the Pole Pieces, the temperature of the field did not
exceed the designed temperature therefore there is no driver to rebuild the Pole
Pieces. Measurements of the ripple springs used to keep the coils tight in the stator slots did not indicate a need to replace or re-wedge the stator.

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.
Work on this project is already underway having commenced in 2019. 2021 will continue with installation of procured equipment and commissioning. Unit 3 will be returned to service (used and useful) by April 2021.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Upgrading the protection and controls systems on Unit 3 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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 134 of 170
Cabinet Gorge Unit 3 Protection & Control Upgrade
Business Case Justification Narrative Page 5 of 6
2.8.2 Identify any related Business Cases.
Cabinet Gorge Units 1, 2 and 4 Protection and Control upgrades

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.
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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 135 of 170
Cabinet Gorge Unit 3 Protection & Control Upgrade
Business Case Justification Narrative Page 6 of 6
The undersigned acknowledge they have reviewed the Cabinet Unit 3 Protection & Control 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.

Business Case Owner

Business Case Sponsor

Steering/Advisory Committee Review

Template Version: 05/28/2020
Glen S. Farmer 7/31/2020
7/31/2020
8-3-2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 136 of 170
Cabinet Gorge Unit 4 Protection & Control Upgrade
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. 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 protection and
controls equipment. This equipment includes speed controllers (governors), voltage
controls (automatic voltage regulation a.k.a. AVR), primary unit control systems (Programmable Logic Controllers) and the protective relay system all of which serve to increase communications and reaction time. Timing for this work is not unrelated to
Avista’s entrance into the Energy Imbalance Market (EIM). The risks for not completing
these upgrades include an inability to quickly respond to market demands thereby
jeopardizing Avista’s ability to serve its customers.

VERSION HISTORY
Version Author Description Date Notes
Draft Glen Farmer Initial draft of original business case 8/1/2020

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 137 of 170
Cabinet Gorge Unit 4 Protection & Control Upgrade
Business Case Justification Narrative Page 2 of 6

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The problem being addressed is the protection and control systems on Cabinet Gorge Unit 3. These systems have reached end of life and serve to provide start, stop, run, change load, react to system changes and protect the generator from electrical disturbances.
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 protection and controls systems were installed in the early 1990’s.
These systems can no longer be maintained due to the manufacturer no longer
supporting the equipment. The customer benefits through higher reliability of Unit controls: i.e. reduced unexpected outages and manufacturer support of upgraded equipment.

1.3 Identify why this work is needed now and what risks there are if not approved or is deferred.
This is an overall protection and control upgrade that addresses all of the components of the generator and turbine thereby ensuring that each auxiliary
system connects and communicates as one. If individual failures were realized,
they would be addressed with a patchwork of components that would not connect and communicate with one another. At some point in time, we would be forced to rework the systems as a whole.

Requested Spend Amount
Requested Spend Time Period 1 year, 2021
Requesting Organization/Department
Business Case Owner | Sponsor
Sponsor Organization/Department
Phase
Category
Driver
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 138 of 170
Cabinet Gorge Unit 4 Protection & Control 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.
This protection and control upgrade mirrors thirteen previous upgrades at
various plants throughout Avista’s generating facilitates. It provides consistency
on the auxiliary systems for maintenance and troubleshooting. Reduced reliance on manufacturer support decreases overall maintenance costs for auxiliary equipment. Interchangeability of the equipment and knowledge transfer amongst technicians plays a key role in reliability.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
No studies per se have been performed however, lessons learned from the previous thirteen upgrades have been incorporated into this design.

Option Capital Cost Start Complete
Replace Unit Control, Monitoring and Protection
System [CURRENT PLAN]
$2,000,000 01/2021 04/2022
Replace Unit Control, Monitoring and Protection System, Reinsulate Pole Pieces and Stator Re-wedge [ALTERNATIVE PLAN]
$3,000,000 01/2021 07/2022
2.1 Describe what metrics, data, analysis or information was considered when preparing this capital request.
Capital planning for this work consisted of bids from manufacturers to determine
best cost and schedule. Consistent communication platform between auxiliary equipment was used to determine best compatibility. Information from previous projects was used to determine installation costs and schedules.

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.
Installation and commissioning of purchased equipment will take place in 2021.
Maintenance costs will not be reduced per se but, Unit reliability will be improved through decreased outages.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 139 of 170
Cabinet Gorge Unit 4 Protection & Control 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.
Design processes, purchasing processes, PI (IO to data historian) will be impacted, new control screens (HMI) for checkout, upgraded protection enables
the protection group to have direct communication with the relays.

2.4 Discuss the alternatives that were considered and any tangible risks and mitigation strategies for each alternative.
With regard to rebuilding the Pole Pieces, the temperature of the field did not
exceed the designed temperature therefore there is no driver to rebuild the Pole
Pieces. Measurements of the ripple springs still needs to be performed to determine the necessity of a rewedge.

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.
Work on this project is already underway having commenced in 2019. 2021 will continue with installation of procured equipment and commissioning. Unit 3 will be returned to service (used and useful) by April 2021.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Upgrading the protection and controls systems on Unit 3 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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 140 of 170
Cabinet Gorge Unit 4 Protection & Control Upgrade
Business Case Justification Narrative Page 5 of 6
2.8.2 Identify any related Business Cases
Cabinet Gorge Units 1, 2 and 4 Protection and Control upgrades

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.
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.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 141 of 170
Cabinet Gorge Unit 4 Protection & Control Upgrade
Business Case Justification Narrative Page 6 of 6
The undersigned acknowledge they have reviewed the Cabinet Unit 3 Protection & Control 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.

Business Case Owner

Business Case Sponsor

Steering/Advisory Committee Review

Template Version: 05/28/2020
Glen S. Farmer 7/31/2020
7/31/2020
8-3-2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 142 of 170
Post Falls Landing and Crane Pad Development
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY

The property located adjacent to the North Channel of the Post Falls Hydroelectric
Development (HED) is being developed by the City of Post Falls for public use as a
recreational area. In connection with the purchase of the property, the City of Post Falls
and Avista have agreed to develop the area in such a way that it could be utilized by
Avista for staging a crane, barges and equipment for maintenance and construction in
support of the Post Falls HED. The area would be joint use and when not needed by
Avista, the area would be utilized by the City of Post Falls and the public for recreational
purposes.

VERSION HISTORY
Version Author Description Date Notes
Draft Bob Weisbeck Initial executive summary 7/20/2020
1.0 Bob Weisbeck Final version approved 8/2/2020

GENERAL INFORMATION

Requested Spend Amount $3,110,000
Requested Spend Time Period 1 year
Requesting Organization/Department C07/GPSS
Business Case Owner | Sponsor Bob Weisbeck | Andy Vickers
Sponsor Organization/Department C07/GPSS
Phase Execution
Category Project
Driver Asset Condition
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 143 of 170
Post Falls Landing and Crane Pad Development
Business Case Justification Narrative Page 2 of 6
1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
Staging heavy equipment for major work at the Post Falls HED is difficult due to the
access and space constraints of the locations of spillways and the powerhouse on
the Spokane River. Staging equipment at Post Falls Park, which is the likely area,
near the plant, will disrupt the public use of the park and present safety hazards to
the public. In addition, access to this area is limited due to the size and capacity of
the bridges across the river. The proposed site of the landing greatly increases the
access for cranes, barges and heavy equipment needed to support construction
and maintenance of the plant.

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 business drivers for this project are Asset Condition and Failed Equipment.
The Post Falls North Channel spillway is over 110 years old. There have been
upgrades to the gates and repair of the spillway, but the structure has reached
the end of its useful life and needs a major rehabilitation or replacement. This
work is expected to begin in 2022.
In addition, Unit #6 has failed and since it has reached the end of its useful life,
cannot be repaired. Replacing this unit individually would not be practical
because auxiliary and critical plant systems need to also be replaced. A study
was performed in 2016 and the recommendation is to perform an entire facility
overhaul. These projects will require access for the transport and installation
major components plant, involving barges and heavy equipment. The
construction of this landing will greatly simplify the process of getting heavy
equipment and materials to the Post Falls facilities.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The work related to Post Falls cannot be delayed much longer. The North
Channel Spillway has reached the end of its useful life. The generating units
are outdated and are at or near the end of their useful lives. Unit #6 has failed
which is evidence that it is past time to rehabilitate this facility. The risk is that
more and more of the units might fail and the operation of the spillway could
become compromised. This could have serious repercussions with operating
the plant and controlling the flow of the Spokane River and the elevation of
Coeur d’Alene Lake. This could also result in violations of the Spokane River
Licensing agreement which would present a serious risk to Avista. The
construction of the landing will enable a more accessible staging area in support
of this work, streamlining the staging of equipment and materials.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 144 of 170
Post Falls Landing and Crane Pad Development
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.
In 2014 through 2015 the rehabilitation project for the South Channel of Post
Falls took place. The project revealed the serious degradation of the concrete
in the spillway and verification that the gate and gate structures were well past
their useful life. This project required extensive use of heavy equipment and
barges to successfully complete this project. The rehabilitation of the North
Channel will be more extensive and will require increased amount of heavy
equipment and barges. The landing will greatly increase the access to the area
for this equipment and be less disruptive to public areas since the work and
access will be straightforward and more easily isolated from the public access.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem.
The South Channel Spillway project can be used as a calibration for this
project. The North Channel Project which planned for 2022 will require
more heavy equipment and barge use than the South Channel. This
landing will provide an effective approach to supporting this work.
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.
An assessment of the landing was performed in 2018 to understand better
the feasibility and cost of creating this landing and associated recreational
features. The architect’s concept and estimate were used to determine
the high-level scope and cost estimate of this project.

2.
Option Capital Cost Start Complete
Design and Construction $3,110,000 01 2021 12 2021
$0

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

A landscaping architect contractor was hired to create conceptual designs of the
landing for review with the City of Post Falls (City) and Avista. A Memorandum
of Understanding (MOU) was signed by the City and Avista to move forward
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 145 of 170
Post Falls Landing and Crane Pad Development
Business Case Justification Narrative Page 4 of 6
with purchasing the property and developing the area for joint use. The
architects estimate for scope and cost were used as a basis for this capital
request.
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.

This project is expected to take two years. The first-year effort will be the
assessment and the design of the landing and the associated recreational
features. This work will be completed in 2020. The second year, 2021, will
include the construction of the landing and recreational features. That budget
is expected to be $3,110,000.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
No business functions and/or processes will be impacted in order to implement
this business case. If the landing is not constructed, the major construction
projects will be adversely impacted because access to the plant for heavy
equipment is currently limited.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The first alternative is to not move forward with construction of the landing. This
will create challenges for getting heavy equipment and materials to the Post
Falls facilities and spillways due to limited access and the current constraint of
bridge size and capacity. This will significantly affect the timeline and cost of
large projects at the powerhouse and spillways.
If Avista decides to not work with City to develop the property for joint use, the
area will not be available for crane and barge access to the plant. In addition,
the City may elect not to develop the property and loose the opportunity to have
a valuable public area that would benefit our customers in Post Falls.
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 the
assessment and the design of the landing and the associated recreational
features. This work will be completed in 2020. The second year, 2021, will
include the construction of the landing and recreational features. That budget
is expected to be $3,110,000. The project is expected to become used and
useful in December of 2021.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 146 of 170
Post Falls Landing and Crane Pad Development
Business Case Justification Narrative Page 5 of 6
2.6 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
A landscaping architect’s estimate for scope and cost was used as a basis for
this capital request.
2.7 Supplemental Information

2.7.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are the Upper Spokane Hydro
Manager and staff at Post Falls, Environmental Resources and the City of
Post Falls. Other stakeholders may be identified during project initiation.

2.7.2 Identify any related Business Cases
This Business Case is independent of other projects but the goal of
completing the landing before the Post Falls North Channel Rehabilitation
and the Post Falls HED Redevelopment projects would significantly
enhance access to the plant facilities for heavy construction.
3.1 Steering Committee or Advisory Group Information
A formal Project Manager has been assigned to this project due to its size and
complexity. The project will be managed within project management practices
adopted by the Generation Production and Substation Support (GPSS)
department. A Steering Committee has been 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 has included the creation of a Steering Committee
which includes 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. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 147 of 170
Post Falls Landing and Crane Pad Development
Business Case Justification Narrative Page 6 of 6
The undersigned acknowledge they have reviewed the Post Falls Landing and
Crane Pad Development 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
8-2-2020
Manager, Hydro Ops and Maintenance
8/3/2020
Andy Vickers
Director GPSS
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 148 of 170
HM/ Control Software
1 GENERAL INFORMATION
Requested Spend Amount $1 ,200,000
Requesting Organization/Department GPSS
Business Case Owner Kristina Newhouse -Controls Engineering Mgr
Business Case Sponsor Andy Vickers -Director of Generation Production
and Substation Support
Sponsor Organization/Department GPSS
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
The need to address the risk of aging control software and outdated control screens
has been vetted through the Generation Production and Substation Support (GPSS)
planning process.
The Controls Engineering Manager will provide oversight and monthly tracking of
the ongoing work within the project. The advisory group for ongoing vetting includes
the Director of GPSS, the Controls Engineering Manager, the Protection Control
Meter Technician Foreman, the Spokane River Operations Manager, the Clark Fork
River Operations Manager, and the Thermal Plant Operations Manager.
2 BUSINESS PROBLEM
The existing Human Machine Interface (HMI) software, Wonderware sold by
Schneider Electric, will not be supported after 2017. New control screens will 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 HMI control software has reached
end of life. HMI control Software is used to develop control screens 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 HMI control software is needed now to prevent limitations going forward that
will introduce security risks. The existing HMI software runs on Windows 7. Microsoft
will not be supporting Windows 7 after the year 2020. If we do not stay current with
supported operating systems then cyber security risks increase. Replacing
unsupported HMI software will allow upgrading control computers to supported
operating systems such as Windows 10.
In addition, developing new controls screens on a new software platform will
modernize control screens and allow operators to carry out their responsibilities
more effectively. Control Screens will need to be developed for each generating
Business Case Justification Narrative Page 1 of 4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 149 of 170
HM/ Control Software
facility, therefore, a planned approach will allow engineers and technicians to
develop screens over time to coordinate with control upgrades.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Do nothing $0
Purchase new software platform and develop $1,200,000 01/2018 09/2021
new control screens
Upgrade existing software (Wonderware) and $1,000,000 01/ 2018 09/2021
develop new control screens
The preferred alternative is to purchase new HMI control software that better meets
the needs 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 manger is needed to maintain schedule and provide ongoing
coordination. An engineer is also needed to consistently upgrade control screens
at each generating facility, preferably before the year 2020 when Microsoft will no
longer be supporting Windows 7. Engineering will assist with developing a new
server based architecture and developing and commissioning HMI control screens.
The PCM Shop will need a 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 each plant and
provide ongoing support.
Table 1 is an estimate of how progress will be made
over the course of 4 years. It shows what percentage
of sites (12 total) will have new control screens by the
end of 2021
Another alternative is to remain with the current HMI
Control Software vendor (Wonderware) and upgrade
to a new version that has already been purchased
(System Platform). This option will still require the
development of new control screens from scratch and
has the same risks as the preferred alternative. This
alternative only saves the cost in software as a new
Business Case Justification Narrative
Year
2018
2019
2020
2021
Table I
Percentage of
sites with new
control screens
10%
33%
66%
100%
Page 2 of 4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 150 of 170
HM/ Control Software
server based architecture and controls screens are still necessary.
Business Case Justification Narrative Page 3 of 4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 151 of 170
HM/ Control Software
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 needed. However, the
servers will require ongoing support, therefore, increasing O&M costs.
Stakeholders that interface with the HMI Control Screen Software business case
include Controls Engineering, Project Management, Hydro Operations, Thermal
Operations, PCM shop, and Central Systems.
4 APPROVAL AND AUTHORIZATION lfl'II Contrcl ~ff wc..Ye
The undersigned acknowledge they have reviewed the Auteffiation Rc19IBecmcnt
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:
Print Name:
_ __,_ffJ~~---~a~~~-----"----Date: I /10/w I 1
Kristina Newhouse
Title: Controls Engineering Manager
Role: Business Case Owner
Signature:
Print Name:
-~~'--'--h"--~~-----,~----Date: , /;&;/z-17
Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
5 VERSION HISTORY
Version Implemented Revision Approved Approval Reason
By Date By Date
1.0 Kristina 717/2017 Andy 7/10/2017 Initial version
Newhouse Vickers
Template Version: 03/07/2017
Business Case Justification Narrative Page 4 of 4
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 152 of 170
Generation Masonry Building Rehabilitation
1 General information
Requested Spend Amount $ 24,900,000
Requesting Organization/Department LO?/GPSS
Business Case Owner Bob Weisbeck
Business Case Sponsor Andy Vickers
Sponsor Organization/Department AO?/GPSS
Category Project
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
A project manager and a steering committee will be selected by the GPSS'
Leadership Team for this project
2 Business problem
Several Buildings associated with Avista's Power Plants are constructed of Masonry
and are approaching one hundred years in age. These buildings include, The Little
Falls Power House and Gate Building, The Long Lake Power House, the Nine Mile
Power House, The Post Street Building, The Post Falls Power House and
Substation Building. The grout and brick in many cases has begun to fail which is
creating a serious personnel and public hazard as bricks become loose in the walls
and parapets and fall to the ground. This has become critical, especially during the
freeze and thaw cycles in the spring. There also appears to be structural issues in
some of the buildings.
3 Proposal and recommended solution
Option .. •. · .... · .. . .. • ·· ... · ... ··· .. · ·. '-.· ·,--_._ ·-·. ·. Capital Cost ·•••· . ·start·• Complete
Do nothing $0
Alternative 1: Refurbish failed areas of the masonry $20,000,000 03/2019 12/2024
Alternative 2: Replace the buildings $100,000,000 03/2019 12/2029
Do Nothing: The condition of the buildings has deteriorated where more and more
random bricks come loose and fall around the perimeter of the buildings. This is putting
personnel and in the case of Post Street, the public at risk for injury and possibly death.
Replace loose brings and failed mortar on a case by case basis has not proved effective
since each thaw/freeze cycle loosens new bricks. In some cases whole sections of walls
and parapets are at risk.
Alternative 1: The recommended alternative is to perform a comprehensive inspection of
each building and create a refurbishment plan which will remedy the issue long term.
Business Case Justification Narrative Page 1 of2
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 153 of 170
Generation Masonry Building Rehabilitation
With the guidance of Project Accounting, replacement of large sections of the masonry
can be considered a capital investment. A detailed assessment and approach is needed
to prevent further deterioration and prevention of injury or building failure.
Alternative 2: The expensive and not recommended alternative is to replace the buildings
with construction with modern codes for construction. The buildings will be expensive
since they will have to comply with historical preservation. In most cases, rebuilding the
existing facilities will be a challenge for working power houses and substations.
4 Approval and authorization
The undersigned acknowledge they have reviewed the Generation Masonry
Building Rehabilitation 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:
Print Name: Bob Weisbeck
Title:
Role: Business Case Owner
Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
5 version history
Version Implemented Revision Approved Approval Reason
By Date By Date
1.0 Bob Weisbeck 01/29/19 Andy Initial version
Vickers
Template Version: 03/07/2017
Business Case Justification Narrative Page 2 of 2
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 154 of 170


 
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Schedule 4, Page 155 of 170


 
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Schedule 4, Page 156 of 170


 
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Schedule 4, Page 157 of 170


 
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Schedule 4, Page 158 of 170


 
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Schedule 4, Page 159 of 170


 
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Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 160 of 170


 
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Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 161 of 170


 
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Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 162 of 170


 
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Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 163 of 170
Automation Replacement
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

The purpose of this program is to replace aging controllers and meters. Controllers are used to automate, control and monitor Avista’s generating facilities. Each generating unit has a meter that measures MWh and MVARh. The controllers and meters 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 meters proactively on a schedule that takes into account resources and outage availability. The
project cost to replace an outdated meter costs about $40,000 and a 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 10-year plan was provided that captured the various controllers through Avista’s generating facilities that need to be upgraded. This program funded the replacement of five outdated controllers over the last 3 years. These five controllers are in
addition to 10 other controllers that have been replaced as part of other large capital projects. The program allows the overdue replacements of controllers and meters to happen at quicker pace to improve reliability and also support the HMI program and EIM program. The 10-year plan for this
program is on track to replace remaining controllers that are outdated over the next seven years. The majority of meters will be upgraded by 2022 in preparation for the EIM. The risk of not continuing this business case slows progress toward replacing aging and outdated controllers and meters that could results in an unplanned outage or a cyber security issue.
VERSION HISTORY
Version Author Description Date Notes
1.0 7/2/2020
2.0 Complete remaining template 7/31/2020

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 164 of 170
Automation Replacement
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?
The purpose of this program is to replace aging Distributed Control Systems (DCS), Programmable Logic Controllers (PLC) and meters. 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. Each generating unit and station service has a meter that measure MWh and MVARh. Controllers collect meter data that is used in logic programs. Controllers and meters 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 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. Incorporating aging controllers and meters 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 and meters with new standards will reduce cyber security risk identified in section 1.1 and unexpected plant outages that require emergency repair with like equipment. Planned projects to replace aging controllers and meters before
they fail will allow for more efficient upgrades with standardized hardware and software that engineers and technicians are trained on.
Requested Spend Amount $650,000
Requested Spend Time Period 10 years
Requesting Organization/Department Generation Production and Substation Support
Business Case Owner | Sponsor Kristina Newhouse | Andy Vickers
Sponsor Organization/Department Generation Production and Substation Support
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 165 of 170
Automation Replacement
Business Case Justification Narrative 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.
Replacing hardware before it fails and software before it introduces a security risk while moving toward our standardized controllers and meters will be a success. In the past we’ve planned on upgrading controllers and meters 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 and meters being replaced today which is about 1-3 controllers and meters a year.
2. PROPOSAL AND RECOMMENDED SOLUTION
[Recommended Solution] Upgrade Controllers and
Meters
Nothing

Alternative 1 is the preferred alternative. It includes replacing all aging controllers and
meters 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.
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). Include any known or estimated reductions to O&M as a result of this investment.
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 to be spread out over many years. Upgrading controller & meters 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 in include:
• Upper Falls Unit 1 – design 2019,2020 / Construction tentatively scheduled for
2021
• Control Works – design 2019,2020 / Construction tentatively scheduled for 2021
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 166 of 170
Automation Replacement
Business Case Justification Narrative Page 4 of 7
• Boulder Park Balance of Plant - design 2020, 2021 / Construction tentatively scheduled for 2022
• Post Falls Balance of Plant - TBD
• Noxon Rapids Units 1-5 - TBD
• Coyote Springs Unit 2 -TBD
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 maintain existing controllers and meters 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 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.
Alternative 2 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.
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 work began in 2018. This business case has funded the replacement of five outdates controllers over the last 3 years. These five controllers are in addition to 10 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.
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 167 of 170
Automation Replacement
Business Case Justification Narrative Page 5 of 7
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 meters 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 & meters 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
Stakeholders that interface with the Automation Replacement Business Case include:
• 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 does not replace any business cases but it 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 and meters. The oldest of the aging controllers require computer drivers that do not fit in new computers.

Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 168 of 170
Automation Replacement
Business Case Justification Narrative Page 6 of 7
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 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:
Kristina Newhouse
Controls Engineering Manager
Business Case Owner

Date:
Andy Vickers
Director of GPSS
Business Case Sponsor

Date:

Steering/Advisory Committee Review
8/3/2020
8/3/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 169 of 170
Automation Replacement
Business Case Justification Narrative Page 7 of 7

Template Version: 05/28/2020
Exhibit No. 7 Case Nos. AVU-E-21-01 & AVU-G-21-01 J. Thackston, Avista
Schedule 4, Page 170 of 170
Project ID: 4574
Project Name: Separate Overfire Air Bucket Replacements
Plant: Colstrip Steam Electric Station
Unit(s): Unit 4
Estimated Costs: $414,000
Avista Portion: $62,100
Avista Recommendation: Approve
Q: Please describe the project
A: A critical component of the SmartBurn NOx control system are the separated overfire air (SOFA)
buckets. These are essential to meeting environmental compliance. To maintain equipment
function and help provide for NOx emission and opacity control, the separated overfire buckets
(and the top overfire buckets (TOFA)) need to be replaced every 4 years during the overhaul.
These overfire buckets warp with heat exposure over an extended time, which causes buckets to
bind up in the boiler and restrict movement during unit operation. Through inspection during
overhaul, the buckets on Unit 4 have been found to be at the end of life. The SOFA buckets are
scheduled to be replaced during the 2020 overhaul. This allows physical access to all buckets
(SOFA, TOFA, Burner) while scaffold is in the boiler. The process of replacing buckets is most
economical with scaffold as this allows for an effective and cohesive removal of buckets, repairs
to support material, testing of movement, and alignment of all emission control components
associated with the boiler corners at the same time.
Complete failure of the buckets is HIGH if not replace during the U4 2020 outage.
SOFA buckets are a portion of the SmartBurn NOX control system and need to be in good
working order for combustion optimization and PM, opacity, & NOX control.
Q: Did Avista/Talen consider alternatives to the project?
A: The only other option is to Do Nothing and replace SOFA buckets during the next planned outage
in four years in 2024. Not performing this work would result in is a high risk that environmental
compliance (NOX, PM, Opacity) would not be met. This could also result in fines from the DEQ
for violating emissions standards.
In addition to consequences from the resulting non-compliance situation, the Unit would need to
be run at reduced load or be placed offline until new buckets were purchase and installed. The
lead time to obtain SOFA buckets is a 3-4 month lead time.
Q: What was the timeline for completion?
A: The new Overfire Buckets would be purchased in early 2020 so they would be available for
planners to incorporate into the 2020 Unit 4 Overhaul work plans currently scheduled for June
2020. They would be installed during the planned 2020 outage.
Q: What was the final cost of the project and when did it go into service?
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 1 of 35
A: Total cost is estimated to be $414,000. $160,000 of this is material and the balance ($254,000)
labor to remove the old Overfire Air buckets and install the new ones. Work is expected to begin
in 2020 and placed in service in 2020.

Q: Describe the system need for these projects.
A: The ability to control the combustion in the boiler is essential to manage the NOx emissions from
the unit. In addition, proper combustion management is required to manage opacity, PM
emissions, and other elements and properties that result coal is burned. The overfire air system
is a critical component used to manage this combustion process.

The injection of air into the boiler fire at various levels allows the combustion to be lengthened,
that results in less air being combusted to create the same heat for production purposes. By this
process, lower NOx levels are achieved while the fuel is still fully consumed to manage other
constituents of the combustion process.

Collectively, there are several components needed to allow the coal to combust as clean as
possible and still provide the energy needed to produce the power from the unit.

Q: Describe the alternatives and how this solution was chosen?
A: Replacing these buckets during the 2020 overhaul is the only viable alternative if the unit is to
continue to meet its permitted levels and avoid permitted non-compliance.

Q: Did Avista/Talen re-evaluate the alternatives?
A: No

Q: Describe Avista’s/Talen’s project management process that was used to manage this process?
A: Avista does not manage the projects at Colstrip directly. Talen, as contract operator, manages all
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may
be assigned to manage projects depending on complexity.

Q: Describe how Talen kept Avista management informed during this project.
A: Budget to Actual reports are issued to Avista by Talen on a monthly basis. The cost status of
each individual project is reported in these spreadsheet reports

Q: Please describe any material changes that impacted the project scope, schedule or budget.
A:

Q: Provide up-to-date economics over its expected life.
A:

Q: Provide up-to-date environmental liabilities and risks over its expected life.
A:

Q: Does this project extend the plant life beyond anticipated shut down date?
A: No, these buckets are crucial to the combustion process and are therefore right in the
combustion chain. As a result, they are subject to extreme heat and will warp and get out of
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 2 of 35
alignment in a relatively short time. These buckets need to be replaced every three to four
years.

.

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 3 of 35
1
Project ID:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
This represents a pre-approval to start construction of the building in 2019 (rather than waiting to 2020)
so that cutover of the building can take place as soon as possible.
Q: Please describe the project
A:
to 2020) so that cutover of the building can take place as soon as possible.
With the shutdown of Units 1 and 2, a number of items have been identified that will need to be
addressed that affect the near term continued operation of Units 3 and 4. One of these items is
the bulk storage and transfer system for the Calcium Bromide (CaBr2) that is used for mercury
abatement in Units 3 and 4. The existing system is currently housed alongside the Condensate
system in Units 1 and 2. With the demolition and removal of Units 1 and 2, that location will no
longer be serviceable.
A building is to be erected on the East side of Unit 4, just south of the existing Hydrazine
building. It will share a common wall with Unit 4. I will house the Calcium Bromide Bulk tank, and
transfer pumps in one end of the building in an enclosed space with a tank containment built
into the foundation.
On the other end of the building will house the electric shop work area and an area that the
existing break and shear will be placed. The electric shop and the brake and shear area will be
serviced by an electric overhead crane. These work areas are also currently within the Unit 1 and
separate building to house the electric shop, and the CaBr2 building. Conceptually, each building
would be smaller than the single building being proposed.
It turned out to be an estimated three times more expensive to erect the individual buildings
rather than the single larger building. In addition, no alternate space was found where the Break
and Shear Equipment nor the Electric shop could be reasonably located.
Finally, because of the environmental permit requirements for the mercury abatement, the
CaBr2 system must be moved so that it can continue to function. This is a mandatory condition.
Finally, there was consideration of not erecting the building to include the Break and Shear
equipment and the Electric Shop. Without this space, work would need to be contracted out,
likely to the Billings area, and could cause delays in maintenance and corrective actions for the
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 4 of 35
2
Additionally, work areas for the electrical work would be required to be set up throughout the
plant on an ad hoc basis that would reduce efficiencies provided by a central location as well as
solution is injected in the scrubber slurry. This reacts with the mercury and oxidizes the mercury
in the flue gas which can then be captured by the plants existing scrubber equipment. This
system is required to meet EPA Mercury and Air Toxic Standards, commonly referred to as
three concerns of the combination Break and Sheer Equipment, Electric Shop, and CaBr2 bulk
storage and transfer system. All of these are necessary for the cost effective maintenance and
operational compliance of Units 3 and 4 in the near term and until the final disposition of Units 3
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 5 of 35
3
.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 6 of 35
Project IDi: 63.4573
Project Name: Capture Well Treatment System
Plant: Colstrip Steam Electric Station
Unit(s): Units 1 - 4
Project Costs: $13,200,000 Avista Costs: $1,980,000
Costs of this Request $6,600,000 Avista Costs of this Request $990,000
Background: The Water Management System and Coal Combustion Residual are essentially a building
block set of projects that support the same strategic goal – to meet our regulatory obligations and
environmental compliance requirements under the Agreement of Consent (AOC) with the Montana
Department of Environmental Quality (MDEQ) and Environmental Protection Agency (EPA) rules on Coal
Combustion Residuals (CCR). These requirements result in a several multi-year capital projects that will
likely extend out through 2024 that address groundwater quality at the Colstrip site.
A simple process description begins with raw water is piped from the Yellowstone River to Castle Rock
Lake and ultimately to holding tanks at the plant site. This water is used in boilers, cooling towers and
scrubber systems. Fly ash from the scrubber system is transported to the plants which then removes
the excess water and deposits paste into disposal cells. Once the water is clear, it is ultimately
recirculated back to the plants for reuse. All water is reused or lost through evaporation – this is a zero
discharge facility. Throughout the years, water has been lost through seepage from the ponds that has
contaminated the groundwater on the Colstrip site. The AOC is the primary Montana regulatory
mechanism to address the groundwater contamination. This is a multi-year project due to the
complexity and inter-related nature of the ponds.
Due to the significant amount of work required to meet these environmental regulations, this project
has and will continue to have Capital Projects in each year from 2040 through the closure of the Plant.
The overall handling of the close loop water system at Colstrip is subject to these two Environmental
Must Do requirements.
Q: Please describe the project
A: The Colstrip Wastewater Administrative Order on Consent (AOC) requires specific actions by the
plant to remediate impacted groundwater at the Plant Site. The Montana Dept. of
Environmental Quality (MDEQ) approved actions requires treatment of the capture well water as
part of the cleanup of impacted groundwater at the Plant Site.
This project provides funding for a two year design/construction schedule to implement a
groundwater capture treatment system in accordance with the requirements identified in the
Colstrip Wastewater AOC Plant Site Remedy as approved by MDEQ. The construction schedule
meets the requirements of the approved MDEQ remediation for the plant site groundwater
capture wells.
Current groundwater capture rate for the Plant Site area is 165gpm and the Unit 1&2 Stage One
Evaporation Pond (SOEP)/Stage Two Evaporation Pond (STEP) area capture rate is 144gpm. With
these flow rates, the Groundwater Capture Storage Pond (approved for construction in 2019)
would fill in about 3.2 years.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 7 of 35
The MDEQ approved remediation remedy also includes fresh water injection into the plant water
system. To implement this, fresh water injection wells will be installed and additional capture
wells provide this year as required by this approved remedy. Once the remediation injection
wells are operating at full capacity, we expect the total capture rate to be approximately
500gpm. At this full capacity rate, we will fill the Groundwater Capture Storage Pond in about 2
years. The 2-year design and construction schedule proposed with this project will meet the
remediation requirements as approved by MDEQ.
This project will include the design and construction of a new Brine Concentrator, steam supply
unit, and a Crystallizer.
The steam supply unit will provide capacity for this groundwater capture treatment system and
the other groundwater capture treatment systems (currently in service) when all four units cease
operation. In addition, this steam supply unit is capable of supplying steam heating to Units 3&4
if both Units are off during winter months.
Q: Did Avista/Talen consider alternatives to the project?
A: As part of the effort, there were alternatives considered. These included upgrading some ponds
and implementing more rigid institutional controls (i.e. more strict procedures, but with more
costs associated with those more strict procedures), changing existing pumping performance
requirements for the site and adding a treatments system, or continuing with the present
operation.
MDEQ ultimately determined that these options were not as effective as the selected option.
Therefore the selected option was written into the Agreement of Consent with the MDEQ to
remedy the water issues at Colstrip.
Q: What was the timeline for completion?
A: The current work plan has engineering and design to start in January 2020 and construction and
installation completed in October 2021. This request is to accelerate the engineering by starting
work in late 2019.
Q: What was the final cost of the project and when did it go into service?
A: n/a at this time (9/19)
Q: Describe the system need for these projects.
A: This system is required for the overall water handling requirements for the Colstrip site. Costs
have been adjudicated between the U12 owners and the U34 owners.
Q: Describe the alternatives and how this solution was chosen?
A: The decision was ultimately MDEQ required.
Q: Did Avista/Talen re-evaluate the alternatives?
A: As stated, this is part of the AOC and not subject to re-evaluation unless ultimately the system
fails to achieve the anticipated results.
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 8 of 35
Q: Describe Avista’s/Talen’s project management process that was used to manage this process?
A: Avista does not manage the projects at Colstrip directly. Talen, as contract operator, manages all
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may
be assigned to manage projects depending on complexity.
Q: Describe how Talen kept Avista management informed during this project.
A: Budget to Actual reports are issued to Avista by Talen on a monthly basis. The cost status of
each individual project is reported in these spreadsheet reports
Q: Please describe any material changes that impacted the project scope, schedule or budget.
A: n/a at this time.
Q: Provide up-to-date economics over its expected life.
A: This is an Environmental Must Do as required by the AOC
Q: Provide up-to-date environmental liabilities and risks over its expected life.
A: Currently, water from existing containment ponds has leaked into the ground water system on
or near the site. This is required to be remediated. It is anticipated that this remediation will
continue on past the operating life of the units.
Q: Does this project extend the plant life beyond anticipated shut down date?
A: This project is required to be continued by AOC even after the Plant may be shut down and
dismantled. This is an ongoing environmental commitment
.
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Revision Summary
Date Revision Initials
11/6/19 Initial Rate Sheet created SEW
10/26/20 Updated to Reflect 2020 and 2021 budgets SEW
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 9 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs:
been subject to several through faults due to in-plant electrical failures. The LTC's (load tap
changers) on Unit 3's Auxiliary transformer have experienced internal arcing failure, oil leakage
and controls failures in the last 5 years. The furanic compound testing of the in service
transformer oil shows insulation aging concerns. Recently the 13.8kv load tap changer failed. The
troubleshooting indicated failed components on a control board. It was repaired by removing a
board from the failed Unit 4 aux transformer and installing it in the Unit 3 aux transformer. The
was made with the transmission lines, the unit starting transformers, and station service bus to
back feed the auxiliary load (normally served by the auxiliary transformer) through this
arrangement. The resulting configuration results in a lot of system losses. In addition, it would
require a significant de-rate on the operating unit in order to start the other unit if it had been
shut down for whatever reason. This placed the entire plant at some risk of losing these key
start up transformers as well. The startup transformers were not designed for this heavy
continual loading condition. There was discussion to serve Unit 3 with this configuration.
Attempts were made to locate a used or rebuilt transformer but the unique configuration of the
1000 MVA rating at the 26kV/13.8kV/4160 winding with load tap changer on both lower voltage
with the four year outage plan for Unit 3. This is currently planned for a window of 56 days
other critical loads necessary to support the generation of steam to power the turbines. These
are very large loads – enough load to serve a small town in many cases. In addition, other
miscellaneous loads needed to run the unit are provided by this source. An auxiliary transformer
is used rather than using the grid as a source in that it can be tapped directly from the output of
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 10 of 35
2
critical loads to a variety of possible failures due to line faults, storms, “driver hits pole”, and
other risks.
or problems, using equipment (i.e. startup transformers) in a manner for which they were not
designed, reduction in system losses, unit reliability, and the wear on the LTC’s a new auxiliary
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

.
i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 11 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

turbine control valves that are removed from Unit 4 in 2020. This work is to ship the removed
valves to have them completely refurbished and prepared so they can be installed as part of the
overhaul for Unit 4 scheduled in 2021. This rebuild is to assure the control valves will perform as
they are crucial for turbine control and over speed protection.

The work 2021 to be performed includes the mobilization of labor, the high velocity oil flush,
bearing work as required, general open and close on the generator, TV pinned seat installation,
GV, TV, IV and RHS valve routine rebuilds, contractor overhead (site support staff, project
management, contract engineering support, office/clerical help, etc.), scaffolding, insulation, tool
use, general steam chest maintenance, NDE testing and maintenance of the bolts and studs on
the valves and steam chest and other assigned duties. This maintenance is performed every
they will function properly to provide the output control for a variety of items including indirectly
managing emissions levels (by managing the output of the turbine, it provides means to make
adjustments to the combustion process that can affect emissions), controlling the turbine output
of an equipment failure or a system failure that could lead to personnel hazards. This work is
intended to be scoped to provide adequate margins for safe and reliable operations between
major outages. While this does not guarantee that systems will not fail between major outages,
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 12 of 35
2
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

.
i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 13 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

completion planned for 2020. As proposed, this project was planned for $4M in 2018, $1.63M in
2019, with $2.62M in 2020. 2020 is the last year of this project.

This project will entail disassembling the IP Turbine and replacing the rotor, stationary blades
(blade rings), and the inner cylinder with new. The current outer cylinder will be re-used. Blade
rows 1-3 and blade rings on both sides of the existing IP Turbine have moderate to severe trailing
edge erosion and some blunt leading edges. The inlet flow guide is out of round due to thermal
distortion and the inner cylinder bolting hardware is starting to bottom out. The initial rows of
the turbine have had shroud repairs to mitigate shroud lifting.

This turbine has been ordered, manufactured, and is currently in storage, ready to be shipped to
damaged ones on the first three stages. Because of the extent of the damage observed in the
the replacement of the IP rotor is $2.719M, which includes $131K for remaining storage cost,
reliability concerns associated with the condition of the IP turbine blades and rings. Some
photos that illustrate the current condition that is causing the concerns are attached here:
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 14 of 35
2

components. In addition, doing nothing was also discussed. At the time the decision was made,
it was determined that replacing the entire turbine blade, ring and rotor sections would best
address plant reliability and would be less expensive to replace rather than repair due to the
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 15 of 35
3
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

.
i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 16 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:

overhaul on Unit 4. The work to be performed includes General NDE, cleaning, blade and seal
inspections and repairs as needed. This work is done during overhaul to ensure proper operation
testing for the two Low Pressure turbines are expected to cost $769k. The balance of the costs
are to address worn and damaged turbine seals that were discovered during the previous
was due to several influences including some debris strike damage, erosion on the blade due to
normal operation, and some minor cracking due to age and wear. If these are not addressed in a
routine way, they could cause a major failure and extended unplanned outage in the future.
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 17 of 35
2

.
i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 18 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:

work as required, general open and close on the generator, TV pinned seat installation, GV, TV,
IV and RHS valve routine rebuilds, contractor overhead (site support staff, project management,
contract engineering support, office/clerical help, etc.), scaffolding, insulation, tool use, general
steam chest maintenance, NDE testing and maintenance of the bolts and studs on the valves and
steam chest and other assigned duties. This maintenance is performed every overhaul to ensure
proper operation and reliability of the turbine/generator.

This work will install a rebuilt turbine valve system that had been previously removed from the
they will function properly to provide the output control for a variety of items including indirectly
managing emissions levels (by managing the output of the turbine, it provides means to make
adjustments to the combustion process that can affect emissions), controlling the turbine output
of an equipment failure or a system failure that could lead to personnel hazards. This work is
intended to be scoped to provide adequate margins for safe and reliable operations between
major outages. While this does not guarantee that systems will not fail between major outages,
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 19 of 35
2
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

.
i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 20 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

Tips. In order to meet environmental emission targets, these elements must perform. To
maintain equipment function and provide for NOx emission and opacity control, buckets (SOFA,
TOFA, and Burner) need to be replaced every 4 years during the overhaul. Buckets warp with
heat exposure over an extended time, which causes buckets to bind up in the boiler and restrict
movement during unit operation. Through inspection during overhaul the buckets are found to
be at the end of life in 3-4 years. Burner buckets/Aux Air tips are scheduled to be replaced on a 4
year plan during an overhaul, this allows physical access to all buckets (SOFA, TOFA, and Burner)
while scaffold is in the boiler. The preventative maintenance process of replacing buckets is most
economical with scaffold as this allows for an effective and cohesive removal of buckets, repairs
to support material, testing of movement, and alignment of all emission components associated
with the boiler corners at the same time. Burner buckets/Aux Air Tips are a portion of the
SmartBurn NOX control system and need to be in good repair for combustion optimization, and
replacement “in-kind” project and is part of the ongoing work on the unit to keep its combustion
system will compliment other emission controls to minimize all emissions from the plant. This
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 21 of 35
2
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 22 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs:

sampling indicating internal problems. Specifically, high levels of acetylene. When the
transformer was opened for inspection, damaged to the tap changer and into the transformer
winding was discovered. The damage was unrepairable. It was determined that the most cost-
effective solution was to place an order for a new transformer and replace the out of service
transformers, and station service bus to back feed the auxiliary load (normally served by the
auxiliary transformer) through this arrangement. The resulting configuration results in a lot of
system losses. In addition, it would require a significant de-rate on the operating unit in order to
start the other unit if it had been shut down for whatever reason. This placed the entire plant at
some risk of losing these key start up transformers as well. The startup transformers were not
designed for this heavy continual loading condition. There was discussion to serve Unit 3 with
this configuration.

Attempts were made to locate a used or rebuilt transformer but the unique configuration of the
1000 MVA rating at the 26kV/13.8kV/4160 winding with load tap changer on both lower voltage
windings is very rare. No other units were located.

Inquiries were also made to assess if repair was an option, but vendor quotes indicated it was far
with the four year outage plan for Unit 3. This is currently planned for a window of 56 days
starting in early May of 2021. The final schedule will be determined later.

Update: the U4 Aux transformer arrived on site in April 2020. Because of concerns with the
COVID-19 Pandemic, a small outage of three weeks was taken in May to inspect Unit 4 in
advance of the major overhaul outage rescheduled to September 2020. During this three week
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 23 of 35
2
other critical loads necessary to support the generation of steam to power the turbines. These
are very large loads – enough load to serve a small town in many cases. In addition, other
miscellaneous loads needed to run the unit are provided by this source. An auxiliary transformer
is used rather than using the grid as a source in that it can be tapped directly from the output of
the generator, saving considerable system losses if the power is sourced through the
transmission system. If the grid was used to source this load, it exposes the plant and these
critical loads to a variety of possible failures due to line faults, storms, “driver hits pole”, and
other risks.
or problems, using equipment (i.e. startup transformers) in a manner for which they were not
designed, reduction in system losses, unit reliability, and the wear on the LTC’s a new auxiliary
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may
each individual project is reported in these spreadsheet reports. In addition, this item was

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 24 of 35
3
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Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 25 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs:

was ordered in 2019. This project is to replace major
sections of the air heat transfer baskets on B Air
Preheater (APH).
Because of the
arrangement of
the baskets they
wear on the
inner rows and
some have
caused damaged to the intermediate baskets. The wear
on the baskets has caused the hot end baskets to fall apart
and drop onto the top of the hot intermediate baskets.
This has resulted in APH pluggage that cannot be
mitigated with a high pressure wash. The only way to
restore full function of the APH is to replace baskets .

Choosing to continue to run in their current condition would result in a continual failure of the
system and the ability to preheat air for the combustion process. This would result in a
significant decrease in unit performance.

Removing the Air Preheater is not a viable option as this is a critical element in the heat cycle
process and unit performance would significantly change increasing the operating expense of the
plant and increasing cost to customers.

The replacement option was chosen as it will restore a normal operating condition to the unit
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 26 of 35
2
flue gas and transfers it to the boiler make up air before the fire. It takes less heat bring hot air
to reach operating temperatures within the boiler than colder air. This process improves the
more expensive and not improve performance. Removing the system would deprive the overall
boiler of a significant efficiency improvement and cost more in fuel and likely reduce output to
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 27 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

further complicated by structural failures within the cooling tower structure. As these structural
members fail due to normal age and wear, it causes those parts of the fill material, that those
members supported, to fail and the brittle remnants of the failed cooling tower cause the
circulating water system to plug up.
This project will replace those failed members. In addition, work to replace the poorest
condition structural members that are still in service will be undertaken. New fill material will be
installed over these new members that will help restore the cooling tower function.
This is a partial retrofit intended to allow reasonable operation until a similar project will be
members and associated fill.

The team also considered an option that would only replace those members that had either
failed and the most at risk members based upon a pre-outage inspection. This would not correct
the cooling tower for a long run but would expect to get through to the next overhaul outage.

Additionally, discussions also centered around if the work needed to be done at all. It was
further complicated by structural failures within the cooling tower structure. As these structural
members fail due to normal age and wear, it causes those parts of the fill material that they
supported to fail and the brittle remnants of the failed cooling tower cause the circulating water
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 28 of 35
2
the most critical items at this time would be the appropriate course at this time. Doing nothing
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number Project Management Professionals and engineers who may

i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 29 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

water that seeps from the ponds into the ground. These wells collect this water to keep it from
water on the site is to be remediated. Any discussion of options is provided through the process
of negotiations and process of settlement for the AOC with the Montana Department of
of the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number of Project Management Professionals and engineers who
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 30 of 35
2

i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 31 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

3&4 EHP to promote capture of water that seeps from the ponds into the ground. These wells
inject fresh water into the ground to promote flows into the capture wells at the edge of the
water on the site is to be remediated. Any discussion of options is provided through the process
of negotiations and process of settlement for the AOC with the Montana Department of
the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number of Project Management Professionals and engineers who
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 32 of 35
2

i
Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 33 of 35
1
Project IDi:
Project Name:
Plant:
Unit(s):
Project Costs: Avista Costs:
2020 Costs

(CCR) material created by units 3&4. This is required as part of the Administrative Order of
water on the site is to be remediated. Any discussion of options is provided through the process
of negotiations and process of settlement for the AOC with the Montana Department of
the projects. They use Primavera as a software solution to keep projects on budget and on
schedule. Talen’s employs a number of Project Management Professionals and engineers who
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 34 of 35
2

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Revision Summary
Date Revision Initials

Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 5, Page 35 of 35
Entire Document is CONFIDENTIAL
2018 Renewable RFP Report and Documentation
Pages 1 through 76
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 6(R), Page 1 of 1
Entire Document is CONFIDENTIAL
Power Purchase Agreement dated March 7, 2019
between Avista and Rattlesnake Flat, LLC
Pages 1 through 224
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 7(R), Page 1 of 1
Entire Document is CONFIDENTIAL
Board documentation concerning the
Rattlesnake Flat Wind Power Purchase Agreement
Pages 1 through 4
Exhibit No. 7 Case Nos. AVU-E-21-01 J. Thackston, Avista
Schedule 8(R), Page 1 of 1
2017 Electric Integrated
Resource Plan
Long Lake Dam
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 1 of 205
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. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 2 of 205
Production Credits
Primary Avista 2017 Electric IRP Team
Individual Title
Clint Kalich Manager of Resource Planning & Analysis
James Gall IRP Manager
John Lyons Senior Resource Policy Analyst Grant Forsyth Senior Forecaster & Economist Richard Maguire System Planning Engineer
2017 Electric IRP Contributors
Name Title
Thomas Dempsey Manager, Generation Joint Projects
Tom Pardee Natural Gas Planning Manager
Amber Gifford DSM Planning and Analytics Manager
Ryan Finesilver DSM Analyst
Jeff Schlect Senior Manager of FERC Policy and Transmission Services
Dave Schwall Senior Engineer
Darrell Soyars Manager of Corporate Environmental Compliance
Xin Shane Senior Power Supply Analyst Debbie Simock Senior External Communications Manager Jason Graham Mechanical Engineer
Contact contributors via email by placing their names in this email address format:
[e-mail]
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 3 of 205
2017 Electric IRP Introduction

Avista has a 128-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 resources. The 2017 Integrated Resource Plan (IRP) continues this legacy by looking 20 years into
the future to determine the energy needs of our customers. The IRP, updated every two years, analyzes and outlines a strategy to meet the projected demand and renewable portfolio standards through energy efficiency and a diverse mix of renewable and traditional energy resources. Summary The 2017 IRP shows Avista has adequate resources between owned and contractually
controlled generation, combined with conservation and market purchases, to meet customer needs through 2026. In the longer term, plant upgrades, energy efficiency measures, solar, demand response, energy storage and additional natural gas-fired
generation are integral parts of Avista’s 2017 Preferred Resource Strategy. Changes
Major changes from the 2015 IRP include:
 The 2017 Expected Case energy forecast grows 0.47 percent per year, replacing the 0.6 percent annual growth rate in the last IRP.
 Peak load growth is lower than energy growth, at 0.42 percent in the winter and 0.46 percent in the summer.
 Lower expected load growth combined with recent Mid-Columbia hydroelectric
contracts, energy efficiency, and demand response delay the need for additional resources from the end of 2020 until 2026.
 The return of demand response (temporarily reducing the demand for energy) and the addition of energy storage and solar.
 Lower expected emissions from Avista owned and controlled resources with
fewer natural-gas fired peaking plants and no new combined-cycle plants. Highlights Some highlights of the 2017 IRP include:
 Avista’s current generation resources remain cost effective and reliable sources of power to meet future customer needs over the next 20 years.
 Energy storage costs are significantly lower than the last IRP which for the first time makes the technology operationally attractive in meeting energy needs in the 20-year timeframe of the 2017 IRP.
 Avista is working to construct a 15 MW (DC) solar facility for the company’s new Solar Select Program for commercial and industrial customers.
 This study estimates conservation will serve 53.3 percent of future load growth.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 4 of 205
IRP Process
Each IRP is a thoroughly researched and data-driven document that identifies and describes a Preferred Resource Strategy to meet customer needs while balancing costs and risk measures with environmental and other policy mandates. Avista’s professional
energy analysts use sophisticated modeling tools and input from over 100 invited participants to develop each plan. The participants in the public process include customers, academics, environmental 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 2019 IRP in mid-2018. 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. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 5 of 205
Table of Contents
1. Executive Summary ...................................................................................................... 1-1
Resource Needs ....................................................................................................................... 1-1 Modeling and Results ............................................................................................................... 1-2 Electricity and Natural Gas Market Forecasts .......................................................................... 1-2 Energy Efficiency Acquisition ................................................................................................... 1-3 Preferred Resource Strategy ................................................................................................... 1-4 Energy Independence Act Compliance .................................................................................... 1-5 Greenhouse Gas Emissions .................................................................................................... 1-6 Action Items .............................................................................................................................. 1-7 2. Introduction and Stakeholder Involvement ................................................................ 2-1 IRP Process ............................................................................................................................. 2-1 2017 IRP Outline ...................................................................................................................... 2-4 Regulatory Requirements ........................................................................................................ 2-6 3. Economic & Load Forecast .......................................................................................... 3-1 Introduction & Highlights .......................................................................................................... 3-1 Economic Characteristics of Avista’s Service Territory ............................................................ 3-1 IRP Long-Run Load Forecast ................................................................................................ 3-13 Monthly Peak Load Forecast Methodology ............................................................................ 3-19 Simulated Extreme Weather Conditions with Historical Weather Data ................................. 3-20 Extreme Temperature Analysis .............................................................................................. 3-24 4. Existing Supply Resources .......................................................................................... 4-1 Introduction & Highlights .......................................................................................................... 4-1 Spokane River Hydroelectric Developments ........................................................................... 4-2 Clark Fork River Hydroelectric Development ........................................................................... 4-4 Total Hydroelectric Generation ................................................................................................ 4-4 Thermal Resources .................................................................................................................. 4-5 Power Purchase and Sale Contracts ....................................................................................... 4-6 Customer-Owned Generation .................................................................................................. 4-9 Solar ....................................................................................................................................... 4-11 5. Energy Efficiency & Demand Response ..................................................................... 5-1 Introduction ............................................................................................................................... 5-1 The Conservation Potential Assessment ................................................................................. 5-2
Overview of Energy Efficiency Potential .................................................................................. 5-5 Conservation Targets ............................................................................................................... 5-7
NPCC’s Seventh Power Plan Benchmarking ........................................................................... 5-8 Energy Efficiency-Related Financial Impacts ......................................................................... 5-11 Integrating Results into Business Planning and Operations .................................................. 5-11
Conservation’s T&D Deferral Analysis ................................................................................... 5-13 Generation Efficiency Audits of Avista Facilities .................................................................... 5-14 Demand Response ................................................................................................................. 5-16 6. Long-Term Position ....................................................................................................... 6-1 Introduction & Highlights .......................................................................................................... 6-1 Reserve Margins ...................................................................................................................... 6-1 Energy Imbalance Market ........................................................................................................ 6-6 Balancing Loads and Resources ............................................................................................. 6-6 Washington State Renewable Portfolio Standard .................................................................... 6-9 7. Policy Considerations ................................................................................................... 7-1 Environmental Issues ............................................................................................................... 7-1
Avista’s Climate Change Policy Efforts .................................................................................... 7-3 8. Transmission & Distribution Planning ........................................................................ 8-1 Introduction ............................................................................................................................... 8-1 Avista Transmission System .................................................................................................... 8-1
Transmission Planning Requirements and Processes ............................................................ 8-3
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Annual Transmission Planning Report ..................................................................................... 8-5 IRP Generation Interconnection Options ................................................................................. 8-6 Distribution Planning ................................................................................................................ 8-7 9. Generation Resource Options...................................................................................... 9-1
Introduction ............................................................................................................................... 9-1 Assumptions ............................................................................................................................. 9-1 Natural Gas-Fired Combined Cycle Combustion Turbine ........................................................ 9-3 Hydroelectric Project Upgrades and Options ......................................................................... 9-14 Thermal Resource Upgrade Options ..................................................................................... 9-16 Ancillary Services Valuation ................................................................................................... 9-17 10. Market Analysis ........................................................................................................... 10-1 Introduction ............................................................................................................................. 10-1 Marketplace ............................................................................................................................ 10-1 Fuel Prices and Conditions .................................................................................................... 10-6 Greenhouse Gas Emissions and the Clean Power Plan ..................................................... 10-10 Risk Analysis ........................................................................................................................ 10-12 Market Price Forecast .......................................................................................................... 10-19 Scenario Analysis ................................................................................................................. 10-27 11. Preferred Resource Strategy ...................................................................................... 11-1 Introduction ............................................................................................................................. 11-1 Supply-Side Resource Acquisitions ....................................................................................... 11-1 Resource Deficiencies............................................................................................................ 11-2 Preferred Resource Strategy ................................................................................................. 11-7 Efficient Frontier Analysis ..................................................................................................... 11-13 Determining the Avoided Costs of Energy Efficiency ........................................................... 11-17 Determining the Avoided Cost of New Generation Options ................................................. 11-18 12. Portfolio Scenarios ...................................................................................................... 12-1 Introduction ............................................................................................................................. 12-1 Colstrip Scenarios .................................................................................................................. 12-2 Other Resource Scenarios ................................................................................................... 12-10 Washington State Emission Goal Analysis .......................................................................... 12-14 13. Action Items ................................................................................................................. 13-1 Summary of the 2015 IRP Action Plan................................................................................... 13-1 2017 IRP Two Year Action Plan ............................................................................................. 13-3
Exhibit No. 7 Case No. AVU-E-21-01 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: Annual and Cumulative Energy Efficiency Acquisitions ............................................. 1-3 Figure 1.5: Efficient Frontier ......................................................................................................... 1-5
Figure 1.6: Avista’s Qualifying Renewables for Washington State’s EIA ..................................... 1-6 Figure 3.1: MSA Population Growth and U.S. Recessions, 1971-2016 ....................................... 3-2 Figure 3.2: Avista and U.S. MSA Population Growth, 2007-2016 ................................................ 3-3 Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2016 .............................. 3-4 Figure 3.4: Avista and U.S. MSA Non-Farm Employment Growth, 2007-2016 ........................... 3-4 Figure 3.5: MSA Personal Income Breakdown by Major Source, 2015 ....................................... 3-5 Figure 3.6: Avista and U.S. MSA Real Personal Income Growth, 1970-2013 ............................. 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, 2000-2016 ............................................. 3-11 Figure 3.10: Forecasting Population Growth .............................................................................. 3-12 Figure 3.11: Long-Run Annual Residential Customer Growth ................................................... 3-16 Figure 4.1: 2018 Avista Capability & Energy Fuel Mix ................................................................. 4-1
Figure 4.2: Avista’s Net Metering Customers ............................................................................. 4-10 Figure 5.1: Historical Conservation Acquisition (system) ............................................................. 5-2 Figure 5.2: Analysis Approach Overview ..................................................................................... 5-3 Figure 5.3: Achievable Conservation Potential Assessment (20-Year Cumulative) .................... 5-6 Figure 5.4: Washington Annual Achievable Potential Energy Efficiency (Megawatt Hours)........ 5-7 Figure 5.5: 2017 Avista CPA / Seventh Power Plan Benchmark Comparison ............................ 5-9 Figure 6.1: Winter One-Hour Capacity Load and Resources ....................................................... 6-7 Figure 6.2: Summer One-Hour Capacity Load and Resources ................................................... 6-7 Figure 6.3: Annual Average Energy Load and Resources ........................................................... 6-9 Figure 8.1: Avista Transmission System ...................................................................................... 8-1 Figure 8.2: Avista 230 kV Transmission System .......................................................................... 8-2 Figure 8.3: Avista Transmission System Planning Regions ......................................................... 8-3 Figure 8.4: NERC Interconnection Map ....................................................................................... 8-4 Figure 9.1: Northwest Wind Project Levelized Costs per MWh ................................................... 9-7 Figure 9.2: Solar Nominal Levelized Cost ($/MWh) ..................................................................... 9-9 Figure 9.3: Historical and Planned Hydro Upgrades .................................................................. 9-14
Figure 9.4: Storage’s Value Stream ........................................................................................... 9-18 Figure 10.1: NERC Interconnection Map ................................................................................... 10-2 Figure 10.2: 20-Year Annual Average Western Interconnect Energy ........................................ 10-3 Figure 10.3: Resource Retirements (Nameplate Capacity) ....................................................... 10-4 Figure 10.4: Cumulative WECC Generation Resource Additions (Nameplate Capacity) .......... 10-5 Figure 10.5: Henry Hub Natural Gas Price Forecast .................................................................. 10-7 Figure 10.6: Northwest Expected Energy ................................................................................... 10-9 Figure 10.7: Regional Wind Expected Capacity Factors .......................................................... 10-10 Figure 10.8: Historical Stanfield Natural Gas Prices (2004-2015) ........................................... 10-12 Figure 10.9: Stanfield Annual Average Natural Gas Price Distribution .................................... 10-13 Figure 10.10: Stanfield Natural Gas Distributions .................................................................... 10-14 Figure 10.11: Stanfield Natural Gas Annual Price Statistical Comparison............................... 10-14 Figure 10.12: Wind Model Output for the Northwest Region ................................................... 10-18 Figure 10.13: 2016 Actual Wind Output BPA Balancing Authority ........................................... 10-19
Figure 10.14: Mid-Columbia Electric Price Forecast Range .................................................... 10-21 Figure 10.15: Western States Greenhouse Gas Emissions ..................................................... 10-22 Figure 10.16: Emission Intensity Metric.................................................................................... 10-23 Figure 10.17: Instate Emission Intensity Change from 2018 to 2037 ...................................... 10-24 Figure 10.18: Base Case Western Interconnect Resource Mix ............................................... 10-24
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Figure 10.19: Western Interconnect Resource Mix Changes .................................................. 10-25 Figure 10.20: Northwest Greenhouse Gas Emission Shadow Prices ...................................... 10-26 Figure 10.21: Washington Clean Air Rule Pricing .................................................................... 10-27 Figure 10.22: Annual Mid-Columbia Flat Price Forecast Colstrip Retires Scenario ................ 10-28 Figure 10.23: No Colstrip Scenario Annual Western U.S. Greenhouse Gas Emissions ......... 10-29 Figure 10.24: Colstrip Emissions & Pricing .............................................................................. 10-29 Figure 10.25: Greenhouse Gas Reduction ............................................................................... 10-31 Figure 10.26: Mid-Columbia Electric Price Comparison........................................................... 10-31 Figure 10.27: 2037 Generation Mix Comparison ..................................................................... 10-32 Figure 11.1: Resource Acquisition History ................................................................................. 11-2 Figure 11.2: Physical Resource Positions (Includes Energy Efficiency) .................................... 11-3 Figure 11.3: REC Requirements versus Qualifying RECs for EIA ............................................. 11-4 Figure 11.4: Conceptual Efficient Frontier Curve ....................................................................... 11-6 Figure 11.5: New Resources to Meet Winter Peak Loads ......................................................... 11-8 Figure 11.6: Load Forecast with and without Energy Efficiency .............................................. 11-10
Figure 11.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions ............. 11-11 Figure 11.8: Projected Power Supply Expense Range ............................................................ 11-13 Figure 11.9: Expected Case Efficient Frontier .......................................................................... 11-14 Figure 11.10: Risk Adjusted PVRR of Efficient Frontier Portfolios ........................................... 11-15
Figure 11.11: Risk Adjusted PVRR of Efficient Frontier Portfolios ........................................... 11-16 Figure 12.1: Colstrip Retires Scenario Cost versus Risk ........................................................... 12-4 Figure 12.2: High-Cost Colstrip Retention Scenario Efficient Frontier ....................................... 12-7 Figure 12.3: High-Cost Colstrip Scenarios Annual Cost ............................................................ 12-8 Figure 12.4: Greenhouse Gas Emissions: Retire Colstrip in 2023 versus PRS ........................ 12-8 Figure 12.5: 50 Percent Colstrip Dispatch Reduction Scenario Cost & Risk Comparison ......... 12-9 Figure 12.6: Colstrip Dispatch Reduction Scenario Greenhouse Gas Comparison ................ 12-10 Figure 12.7: Other Resource Strategy Portfolio Cost and Risk (Millions) ................................ 12-11 Figure 12.8: Avista Direct Greenhouse Gas Emissions ........................................................... 12-15
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 9 of 205
Table of Tables
Table 1.1: The 2017 Preferred Resource Strategy ...................................................................... 1-4 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: Idaho IRP Requirements ............................................................................................. 2-6 Table 2.4: Washington IRP Rules and Requirements .................................................................. 2-6 Table 3.1: UPC Models Using Non-Weather Driver Variables ..................................................... 3-8 Table 3.2: Customer Growth Correlations, January 2005 – December 2013 ............................ 3-11 Table 4.1: Avista-Owned Hydroelectric Resources ...................................................................... 4-4 Table 4.2: Avista-Owned Thermal Resources .............................................................................. 4-5 Table 4.3: Mid-Columbia Capacity and Energy Contracts ........................................................... 4-8 Table 4.4: PURPA Agreements .................................................................................................... 4-8 Table 4.5: Other Contractual Rights and Obligations ................................................................... 4-9 Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ...................... 5-5 Table 5.2: Annual Achievable Potential Energy Efficiency (Megawatt Hours) ............................. 5-8 Table 5.3: Annual Achievable Potential Energy Efficiency (Megawatt Hours) ............................. 5-8 Table 5.4: Transmission and Distribution Benefit ....................................................................... 5-14 Table 5.5: Preliminary Generation Facility Efficiency Upgrade Potential ................................... 5-15 Table 5.6: Planned Generation Facility Efficiency Upgrades 2017 – 2018 ................................ 5-16 Table 5.7: Commercial and Industrial Demand Response Achievable Potential (MW) ............. 5-18 Table 6.1: Washington State EIA Compliance Position Prior to REC Banking (aMW) .............. 6-10 Table 7.1: Avista Owned and Controlled PM Emissions .............................................................. 7-7 Table 8.1: 2017 IRP Generation Study Transmission Costs ........................................................ 8-7 Table 8.2: Third-Party Large Generation Interconnection Requests ............................................ 8-7 Table 8.3: Capital Deferment Analysis ......................................................................................... 8-9 Table 8.4: Planned Feeder Rebuilds .......................................................................................... 8-10 Table 9.1: Natural Gas-Fired Plant Levelized Costs per MWh .................................................... 9-3 Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics................................... 9-5 Table 9.3: Solar Capacity Credit by Month ................................................................................... 9-8 Table 9.4: Storage Power Supply Value .................................................................................... 9-18 Table 9.5: Natural Gas-Fired Facilities Ancillary Service Value ................................................. 9-19 Table 10.1: AURORAXMP Zones ................................................................................................. 10-2 Table 10.2: Added Northwest Renewable Generation Resources ............................................. 10-6 Table 10.3: Natural Gas Price Basin Differentials from Henry Hub ........................................... 10-8 Table 10.4: Monthly Price Differentials for Stanfield from Henry Hub ........................................ 10-8 Table 10.5: January through June Load Area Correlations ..................................................... 10-15 Table 10.6: July through December Load Area Correlations ................................................... 10-16 Table 10.7: Area Load Coefficient of Determination (Standard Deviation/Mean) .................... 10-16 Table 10.8: Area Load Coefficient of Determination (Standard Deviation/Mean) .................... 10-16 Table 10.9: Annual Average Mid-Columbia Electric Prices ($/MWh) ....................................... 10-21 Table 11.1: Qualifying Washington EIA Resources ................................................................... 11-4 Table 11.2: 2017 Preferred Resource Strategy .......................................................................... 11-7 Table 11.3: 2015 Preferred Resource Strategy .......................................................................... 11-9 Table 11.4: PRS Rate Base Additions from Capital Expenditures ........................................... 11-12 Table 11.5: Alternative Resource Strategies (2035) along the Efficient Frontier (MW) ........... 11-17 Table 11.6: 2017 IRP Avoided Costs ....................................................................................... 11-19 Table 12.1: Load Forecast Scenarios (2018-2037) .................................................................... 12-1 Table 12.2: Resource Selection for Load Forecast Scenarios ................................................... 12-2 Table 12.3: Colstrip Retires- Resource Strategy Options (ISO Conditions MW) ....................... 12-3
Table 12.4: Colstrip Retires in 2023 Scenario Resource Strategy ............................................. 12-7 Table 12.5: No New Thermal Resource Scenario .................................................................... 12-12 Table 12.6: No New Thermal Resource and Colstrip Replacement Scenario ......................... 12-13 Table 12.7: New CCCT Replaces Lancaster Scenario ............................................................ 12-14
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 11 of 205
1. Executive Summary

Avista’s 2017 Electric Integrated Resource Plan (IRP) shapes its resource strategy over the next two years and procurements over the next 20 years. It provides a snapshot of
existing resources and loads and evaluates acquisition strategies over expected and possible future conditions. The 2017 Preferred Resource Strategy (PRS) includes a mix of solar, demand response, energy efficiency, storage, upgrades to existing assets, and
new natural gas-fired generation. The PRS relies on modeling methods to balance cost, reliability, rate volatility, and
renewable requirements. Avista’s management and the Technical Advisory Committee (TAC) guide IRP development through their input on modeling and planning assumptions. TAC members include customers, Commission staff, the Northwest Power and Conservation Council, consumer advocates, academics, environmental groups, utility peers, government agencies, and other interested parties. Resource Needs
Under extreme weather conditions, Avista expects its highest peak loads in the winter. Its peak planning methodology includes operating reserves, regulation, load following, wind integration, a 14 percent planning margin over winter-peak load levels, and a seven percent planning margin over summer-peak load levels. The company has adequate resources combined with conservation to meet peak load requirements through October 2026. Figure 1.1 shows Avista’s resource position through 2037.
Chapter 6 – Long-Term Position details Avista’s resource needs. Figure 1.1: Load-Resource Balance—Winter Peak Load & Resource Availability

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Modeling and Results
Avista uses multiple steps to develop its PRS; beginning with identifying and quantifying potential new generation resources to serve projected electricity demand across the Western Interconnect. This study determines the impact of external markets on the
Northwest electricity marketplace. It then maps existing Avista resources to the transmission grid in a model simulating hourly operations for the Western Interconnect in the 2018 to 2037 IRP timeframe. The model adds new resources and transmission to
the Western Interconnect as regional loads grow and resources retire. Monte Carlo-style analyses vary hydroelectric and wind generation, loads, forced outages and natural gas price data over 500 iterations of potential future market conditions to develop the Mid-Columbia electricity marketplace through 2037. Electricity and Natural Gas Market Forecasts
Figure 1.2 shows the 2017 IRP Mid-Columbia electricity price forecast for the Expected Case, including the range of prices resulting from 500 Monte Carlo iterations. The levelized price is $35.85 per MWh in nominal dollars over the 2018-2037 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 is $4.20 per dekatherm (Dth) over the
next 20 years. See Chapter 10 – Market Analysis for natural gas and electricity price forecasts.
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Figure 1.3: Stanfield Natural Gas Price Forecast
Energy Efficiency Acquisition
Avista commissioned a 20-year Conservation Potential Assessment (CPA) to determine potential residential, commercial and industrial energy efficiency applications. Data from
this study formed the basis of the IRP’s conservation analysis. This study estimates conservation will serve 53.3 percent of future load growth. Since 1978, Avista’s load is 12.3 percent lower due to conservation. Figure 1.4 illustrates the historical efficiency acquisitions as blue bars and the dashed line shows the amount of energy efficiency still reducing loads due to the 18-year assumed measure life. See Chapter 5 – Energy Efficiency and Demand Response for details. Figure 1.4: Annual and Cumulative Energy Efficiency Acquisitions

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Preferred Resource Strategy
The PRS results from careful consideration and input by Avista’s management, the
TAC, and from the information gathered and analyzed in the IRP process. It meets
future load growth with upgrades at existing generation facilities, energy efficiency,
natural gas-fired technologies, storage, energy efficiency, and demand response, as
shown in Table 1.1.
Table 1.1: The 2017 Preferred Resource Strategy
Resource By the End of Year ISO Conditions (MW) Winter Peak (MW) Energy (aMW)
Solar 2018 15 0 3
Natural Gas Peaker 2026 192 204 178
Thermal Upgrades 2026-2029 34 34 31
Storage 2029 5 5 0 Natural Gas Peaker 2030 96 102 89 Natural Gas Peaker 2034 47 47 43 Total 389 392 344 Efficiency Improvements Acquisition Range Winter Peak Reduction (MW)
Energy (aMW)
Energy Efficiency 2018-2037 203 108
Demand Response 2025-2037 44 0
Distribution Efficiencies <1 <1 Total 247 108

The 2017 PRS describes a reasonable low-cost plan along the Efficient Frontier of potential resource portfolios accounting for fuel supply and price risks. Major changes from the 2015 IRP include a lower contribution from natural gas-fired peakers and inclusion of demand response, solar and storage resources. Each new generation resource and energy efficiency option is valued against the Expected Case’s 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 their associated capital and fixed operation and
maintenance (O&M) costs, form the input into Avista’s Preferred Resource Strategy
Linear Programming Model (PRiSM). PRiSM assists Avista by developing optimal mixes of new resources along an efficient frontier. Chapter 11 – Preferred Resource Strategy provides a detailed discussion of the efficient frontier concept. The PRS provides a least reasonable-cost portfolio, minimizing future costs and risks within actual and expected environmental constraints. The Efficient Frontier helps determine the tradeoffs between risk and cost. The approach is similar to finding an optimal mix of risk and return in an investment portfolio, as potential returns increase, so do risks. Conversely, reducing risk generally reduces overall returns. Figure 1.5 presents the change in cost and risk from the PRS on the Efficient Frontier. Lower
power cost variability comes from investments in more expensive, but less risky,
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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resources such as wind and hydroelectric upgrades. The PRS is the portfolio selected
on the Efficient Frontier where reduced risk justifies the increased cost. Figure 1.5: Efficient Frontier
Chapter 12 – Portfolio Scenarios, includes several scenarios identifying tipping points where the PRS could change under different conditions from the Expected Case. It also evaluates the impacts of, among others, varying load growth, resource capital costs,
and greenhouse gas policies.
Energy Independence Act Compliance
Washington’s Energy Independence Act (EIA), or Initiative 937, requires utilities with over 25,000 customers to meet nine percent of retail load from qualified renewable
resources by 2016 and 15 percent by 2020. The initiative also requires utilities to acquire all cost-effective conservation and energy efficiency measures. Avista will meet or exceed its EIA requirements through the IRP timeframe with a combination of qualifying hydroelectric upgrades, the Palouse Wind project, and Kettle Falls Generating Station output. Figure 1.6 shows Avista’s EIA-qualified generation; Chapter 6 – Long-Term Position covers this topic in-depth.
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Figure 1.6: Avista’s Qualifying Renewables for Washington State’s EIA
Greenhouse Gas Emissions
The regulation of greenhouse gases, or carbon emissions, has changed since the 2015 IRP with the change in presidential administrations, resulting in evolving federal and additional state-driven regulation. Some states have active cap and trade programs, emissions performance standards, renewable portfolio standards, or a combination of current and proposed regulations affecting emissions from electric generation resources. Figure 1.7 shows that Avista emissions will decrease over the IRP timeframe. The 2017
IRP’s emissions forecast is 29 percent lower for 2035 than the 2015 IRP’s forecast. Figure 1.8 shows the western-region emissions likely will fall from historic levels.
Regional emissions fall below 1990 levels by the end of the study period due to coal retirements and potential state and federal policies. More details on state and federal greenhouse gas policies are in Chapter 7 – Policy Consideration. Results of
greenhouse-gas policy scenarios are in Chapter 10 – Market Analysis and Chapter 12 – Portfolio Scenarios.
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Figure 1.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
Figure 1.8: U.S. Western Interconnect Greenhouse Gas Emissions
Action Items
The 2017 Action Items chapter updates progress made on Action Items in the 2015 IRP and outlines activities Avista intends to perform between the publication of this report and publication of the 2019 IRP. It includes input from Commission Staff, Avista’s management team, and the TAC. Action Item categories include generation resource-related analysis, energy efficiency, and transmission planning. Refer to Chapter 13 – Action Items for details about each of these categories.

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 18 of 205

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 19 of 205
2. Introduction and Stakeholder Involvement
Avista submits an IRP to the Idaho and Washington public utility commissions biennially.1 Including its first plan in 1989, the 2017 IRP is Avista’s fifteenth plan. It
identifies and describes a PRS for meeting load growth while balancing cost and risk measures with environmental mandates.
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 and optimizing the value of its current portfolio. The IRP is a resource evaluation tool, not a plan for acquiring a particular set of assets. Actual resource acquisition generally occurs through competitive bidding processes.
IRP Process
The 2017 IRP is developed and written with the aid of a public process. Avista actively seeks input from a variety of constituents through the TAC. The TAC is a mix of over 100 invited external participants, including staff from the Idaho and Washington
commissions, customers, academics, environmental organizations, government agencies, consultants, utilities, and other interested parties, who joined the planning process. Avista sponsored six TAC meetings for the 2017 IRP. The first meeting was on June 2, 2016 and the last occurred on June 20, 2017. Each TAC meeting covers different aspects of IRP planning activities. At the meetings, members provide contributions to,
and assessments of, modeling assumptions, modeling processes, and results of Avista studies. Table 2.1 contains a list of TAC meeting dates and the agenda items covered in each meeting.

Agendas and presentations from the TAC meetings are in Appendix A and on Avista’s website at https://www.myavista.com/about-us/our-company/integrated-resource-planning. The website link contains all past IRPs and TAC meeting presentations back to 1989.
1 Washington IRP requirements are contained 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.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 20 of 205
Table 2.1: TAC Meeting Dates and Agenda Items

Meeting Date Agenda Items TAC 1 – June 2, 2016  TAC Meeting Expectations
 2015 IRP Commission Acknowledgements
 2015 Action Plan Update
 Energy Independence Act Compliance
 Energy Efficiency Modeling Discussion
 Resource Adequacy – Preliminary Results
 Draft 2017 Electric IRP Work Plan
TAC 2 – September 28, 2016  Introduction & TAC 1 Recap
 TAC 1 Action Item Update
 Electrification Update
 Load and Economic Forecasts
 Supply Side Options
 Clean Energy Fund 2 Grant Project
TAC 3 – November 8, 2016  Introduction & TAC 2 Recap
 Colstrip Discussion
 Clean Power Plan and Clean Air Rule
 IRP Modeling Overview
 Cost of Carbon
 Avista’s Power Planner Simulator TAC 4 – February 15, 2017  Introduction & TAC 3 Recap
 Resource Needs Assessment
 Natural Gas Price Forecast
 Electric Price Forecast
 Transmission Planning
 Market and Portfolio Scenarios
TAC 5 – March 28, 2017  Introduction & TAC 4 Recap
 Updated Electric Price Forecast
 Energy Storage and Ancillary Services
 Conservation Potential Assessment
 Distribution Planning
 Draft Preferred Resource Strategy
TAC 6 – June 20, 2017  Introduction & TAC 5 Recap
 Conservation Assessment
 Final 2017 Preferred Resource Strategy
 Scenario Analysis
 C&I Solar Select Program
 2019 IRP Action Items
 2017 IRP Document Overview

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 21 of 205
Avista greatly appreciates the valuable contributions of its TAC members and wishes to
acknowledge and thank the organizations that allow their attendance. Table 2.2 is a list of the organizations participating in the 2017 IRP TAC process. Table 2.2: External Technical Advisory Committee Participating Organizations
Organization
AEG
City of Spokane Clearwater Paper Eastern Washington University GE Energy Idaho Conservation League Idaho Department of Environmental Quality Idaho Power Idaho Public Utilities Commission
Inland Empire Paper
NW Energy Coalition
Northwest Power and Conservation Council
PacifiCorp
Pend Oreille PUD
Puget Sound Energy
Renewable Northwest
Residential and Small Commercial Customers
Sierra Club
Snake River Alliance
Spokane Neighborhood Action Partners
The Energy Authority
Washington State Office of the Attorney General
Washington Department of Enterprise Services Washington Utilities and Transportation Commission Whitman County Commission
Issue Specific Public Involvement Activities In addition to TAC meetings, Avista sponsors and participates in several other collaborative processes involving a range of public interests. A sampling is below.
Energy Efficiency Advisory Group
The energy efficiency Advisory Group provides stakeholders and public groups biannual opportunities to discuss Avista’s energy efficiency efforts.

FERC Hydro Relicensing – Clark Fork and Spokane River Projects Over 50 stakeholder groups participated in the Clark Fork hydro-relicensing process beginning in 1993. This led to the first all-party settlement filed with a FERC relicensing
application, and the eventual issuance of a 45-year FERC operating license in February 2003. This collaborative process continues in the implementation of the license and Clark Fork Settlement Agreement, with stakeholders participating in various protection, mitigation, and enhancement efforts. Avista received a 50-year license for the Spokane
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 22 of 205
River Project following a multi-year collaborative process involving several hundred
stakeholders. Implementation began in 2009 with a variety of collaborating parties.
Low Income Rate Assistance Program
This program is coordinated with four community action agencies in Avista’s Washington service territory. The program began in 2001, and quarterly reviews ensure changing administrative issues and needs are met. Regional Planning The Pacific Northwest generation and transmission system operates in a coordinated fashion. Avista participates in the efforts of many regional planning processes. Information from this participation supplements Avista’s IRP process. A partial list of the regional organizations Avista participates in includes:
 Western Electricity Coordinating Council
 Peak Reliability
 Northwest Power and Conservation Council
 Northwest Power Pool
 Pacific Northwest Utilities Conference Committee
 ColumbiaGrid
 Northern Tier Transmission Group
 North American Electric Reliability Corporation Future Public Involvement Avista actively solicits input from interested parties to enhance its IRP process. We continue to expand TAC membership and diversity, and maintain the TAC meetings as an open public process. 2017 IRP Outline
The 2017 IRP consists of 13 chapters plus an 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 2017 IRP. Chapter 2: Introduction and Stakeholder Involvement This chapter introduces the IRP and details public participation and involvement in the IRP planning 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.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 23 of 205
Chapter 5: Energy Efficiency and Demand Response
This chapter discusses Avista energy efficiency programs. It provides an overview of the conservation potential assessment and summarizes energy efficiency and demand response modeling results.
Chapter 6: Long-Term Position This chapter reviews Avista reliability planning and reserve margins, resource requirements, and provides an assessment of its reserves and flexibility. Chapter 7: Policy Considerations This chapter focuses on some of the major policy issues for resource planning,
including state and federal greenhouse gas policies and environmental regulations. Chapter 8: Transmission & Distribution Planning
This chapter discusses Avista distribution and transmission systems, as well as regional transmission planning issues. It includes detail on transmission cost studies used in IRP modeling and provides a summary of our 10-year Transmission Plan. The chapter
concludes with a discussion of distribution efficiency and grid modernization projects; including storage benefits to the distribution system. Chapter 9: Generation Resource Options This chapter covers the costs and operating characteristics of the generation resource options modeled for the IRP. 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 2017 PRS, including the efficient frontier and resulting avoided costs.
Chapter 12: Portfolio Scenarios This chapter discusses the portfolio scenarios and tipping point analyses. Chapter 13: Action Items This chapter discusses progress made on Action Items contained in the 2015 IRP. It details the action items Avista will focus on between publication of this plan and the
2019 IRP.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 24 of 205
Regulatory Requirements
The IRP process for Idaho has several requirements documented in IPUC Orders Nos. 22299 and 25260. Table 2.3 summarizes them. Table 2.3: Idaho IRP Requirements
Requirement Plan Citation
Identify and list relevant operating characteristics of existing resources by categories including: hydroelectric, coal-fired, oil or gas-fired, PURPA
(by type), exchanges, contracts, transmission resources, and others.
Chapter 4- Existing Supply Resources
Identify and discuss the 20-year load forecast plus scenarios for the different customer classes. Identify the assumptions and models used to develop the load forecast.
Chapter 3- Economic & Load Forecast Chapter 12- Portfolio Scenarios
Identify the utility’s plan to meet load over the 20-year planning horizon. Include costs and risks of the plan under a range of plausible scenarios.
Chapter 11- Preferred Resource Strategy Chapter 12- Portfolio Scenarios
Identify energy efficiency resources and costs. Chapter 5- Energy Efficiency & Demand Response
Provide opportunities for public participation and involvement.Chapter 2- Introduction and Stakeholder Involvement
Explain the present load/resource position, expected responses to possible future events, and the role of conservation in those responses.
Chapter 6- Long-Term Position Chapter 12- Portfolio Scenarios Chapter 5- Energy Efficiency & Demand Response
Discuss any flexibilities and analyses considered, 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, and (4) contingencies for upgrading, optioning and acquiring resources.
Chapter 3- Economic & Load Forecast Chapter 4- Existing Supply Resources Chapter 9- Generation Resource Options Chapter 11- Preferred Resource Strategies

The IRP process for Washington has several requirements documented in Washington Administrative Code (WAC). Table 2.4 summarizes where in the document Avista addressed each requirement. Table 2.4: Washington IRP Rules and Requirements
Rule and Requirement Plan Citation
–

–
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 25 of 205
WAC 480-100-238(2)(a) – Plan describes mix of energy supply resources. Chapter 4- Existing Supply Resources Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(a) – Plan describes conservation supply. Chapter 5- Energy Efficiency & Demand Response Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(a) – Plan addresses supply in terms of current and future needs of utility ratepayers.
Chapter 3- Economic & Load Forecast Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – Plan uses lowest reasonable cost (LRC) analysis to select mix of resources.
Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers resource costs. Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers market-volatility risks. Chapter 10- Market Analysis Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers demand side uncertainties. Chapter 5- Energy Efficiency & Demand Response Chapter 12- Portfolio Scenarios
WAC 480-100-238(2)(b) – LRC analysis considers resource dispatchability. Chapter 9- Generation Resource Options Chapter 10- Market Analysis
WAC 480-100-238(2)(b) – LRC analysis considers resource effect on system operation. Chapter 10- Market Analysis Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers risks imposed on ratepayers. Chapter 7- Policy Considerations Chapter 9- Generation Resource Options
Chapter 10- Market Analysis Chapter 11- Preferred Resource Strategy Chapter 12- Portfolio Scenarios
WAC 480-100-238(2)(b) – LRC analysis considers public policies regarding resource preference adopted by Washington state or federal government.
Chapter 3- Economic & Load Forecast Chapter 4- Existing Supply Resources Chapter 7- Policy Considerations Chapter 11- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers cost of risks associated with environmental effects including emissions of carbon dioxide.
Chapter 7- Policy Considerations Chapter 11- Preferred Resource Strategy Chapter 12- Portfolio Scenarios
WAC 480-100-238(2)(c) – Plan defines conservation as any reduction in electric power consumption that results from increases in the efficiency of energy use, production, or distribution.
Chapter 5- Energy Efficiency & Demand Response Chapter 11- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan includes a range of forecasts of future demand. Chapter 3- Economic & Load Forecast Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(a) – Plan develops forecasts using methods that examine the effect of economic forces on the consumption of electricity.
Chapter 3- Economic & Load Forecast Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(a) – Plan develops forecasts using methods that address changes in the number, type and efficiency of end-uses.
Chapter 3- Economic & Load Forecast Chapter 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 26 of 205
WAC 480-100-238(3)(b) – Plan includes an assessment of commercially available conservation, including load management.
Chapter 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution WAC 480-100-238(3)(b) – Plan includes an assessment of currently employed and new policies and programs needed to obtain the conservation improvements.
Chapter 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution
WAC 480-100-238(3)(c) – Plan includes an assessment of a wide range of conventional and commercially available nonconventional generating technologies.
Chapter 9- Generation Resource Options Chapter 11- Preferred Resource Strategy Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(d) – Plan includes an assessment of transmission system capability and reliability (as allowed by current law).
Chapter 8- Transmission & Distribution
WAC 480-100-238(3)(e) – Plan includes a comparative evaluation of energy supply resources (including transmission and distribution) and improvements in conservation
using LRC.
Chapter 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution Chapter 11- Preferred Resource Strategy
WAC-480-100-238(3)(f) – Demand forecasts and resource evaluations are integrated into the long range plan for resource acquisition.
Chapter 5- Energy Efficiency & Demand Response Chapter 8- Transmission & Distribution Chapter 9- Generation Resource Options Chapter 12- Portfolio Scenarios
WAC 480-100-238(3)(g) – Includes a two-year action plan implementing the long range plan. Chapter 13- Action Items
WAC 480-100-238(3)(h) – Plan includes a progress report on the implementation of the previously filed plan.
Chapter 13- Action Items
WAC 480-100-238(5) – Plan includes description of consultation with commission staff and public participation
Chapter 2- Introduction and Stakeholder Involvement
WAC 480-100-238(5) – Plan includes description of work plan. Appendix B
WAC 480-107-015(3) – Proposed request for proposals for new capacity needed within three years of the IRP.
Chapter 10- Preferred Resource Strategy
RCW 19.280.030-1(e) – An assessment of methods, commercially available technologies, or facilities for integrating renewable resources, and addressing overgeneration events, if applicable to the utility's resource portfolio;
Chapter 9- Generation Resource Options Chapter 10- Market Analysis
RCW 19.280.030-1(f) – Integration of demand forecasts and resource evaluations into a long-range assessment describing the mix of supply side generating resources and conservation and efficiency resources that will meet current and projected needs, including mitigating overgeneration events, at the lowest reasonable cost and risk to the utility and its ratepayers.
Chapter 9- Generation Resource Options Chapter 10- Market Analysis

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 27 of 205
3. Economic & Load Forecast
Introduction & Highlights
An explanation and quantification of Avista’s loads and resources are integral to the IRP. This chapter summarizes Expected Case customer and load projections, load growth scenarios, and recent enhancements to our forecasting models and processes.

Economic Characteristics of Avista’s Service Territory
Avista’s core service area for electricity includes a population of 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 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. 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 that when regional employment growth is stronger than U.S. growth over the business cycle, it is associated with increased in-migration. The reverse
holds true. Figure 3.1 shows annual population growth since 1971 and highlights the recessions. 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 Great
Recession reduced population growth from nearly two percent in 2007 to less than one percent from 2010 to 2013. Accelerating service area employment growth in 2013 helped push population growth to around one percent starting in 2014.
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
 Population and employment growth are recovering from the Great Recession.
 The 2017 Expected Case energy forecast grows 0.47 percent per year, replacing the 0.6 percent annual growth rate in the 2015 IRP.
 Peak load growth is lower than energy growth, at 0.42 percent in the winter and
0.46 percent in the summer.
 Retail sales and residential use per customer forecasts continue to decline from 2015 IRP projections.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 28 of 205
Figure 3.1: MSA Population Growth and U.S. Recessions, 1971-2016

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.; 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. 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 based on historical data show that, holding U.S. employment-growth constant, every one percent increase in service area employment growth is associated with a 0.4 percent increase in population growth in the next year.
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 has transitioned from a natural resources-based manufacturing economy to a
services-based 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 one percent of total employment. Spokane and Coeur d’Alene MSAs are major providers of health and higher education services to the Inland Northwest. A recent addition to these sectors is approval from
Washington’s legislature for Washington State University to open a medical school in Spokane, Washington.
3 Data Source: Bureau of Economic Analysis, U.S. Census, and Washington State OFM.
4 Data Source: Bureau of Labor and Statistics.
-1.0%
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Figure 3.2: Avista and U.S. MSA Population Growth, 2007-2016

Non-farm employment growth averaged 2.7 percent per year between 1990 and 2007. However, Figure 3.4 shows that 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.
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.
5 Data Source: Bureau of Labor and Statistics.
6 Data Source: Bureau of Economic Analysis.
1.9%
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0.5%0.5%
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1.1%
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2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
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Avista WA-ID MSAs
U.S.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 30 of 205
Figure 3.3: MSA Non-Farm Employment Breakdown by Major Sector, 2016
Figure 3.4: Avista and U.S. MSA Non-Farm Employment Growth, 2007-2016

Private Goods Producing, 14%
Private Service Producing, 69%
Federal Government, 2%
State Government, 4%
Local Government, 11%
2.2%
0.5%
-4.7%
-1.6%
0.2%
0.6%
2.0%1.8%2.0%
3.0%
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2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
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Avista WA-ID MSAs
U.S.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 31 of 205
Figure 3.5: MSA Personal Income Breakdown by Major Source, 2015
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 23 percent. The relatively high regional dependence on government employment and transfer payments means continued federal fiscal consolidation and transfer program
reform may reduce future growth. Although 57 percent of personal income is from net earnings, transfer payments 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 reflects an aging regional population, a surge of military veterans, and the Great Recession; the later 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. as a result 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 in the previous decade to around 85 percent. The income ratio has not since recovered.
7 Data Source: Bureau of Economic Analysis.
Net Earnings, 57%
Dividends, Interest, and Rent, 20%
Transfer Receipts, 23%
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 32 of 205
Figure 3.6: Avista and U.S. MSA Real Personal Income Growth, 1970-2013
Five-Year Load Forecast Methodology In non-IRP years, the retail and native load forecasts have a five-year time horizon. Avista conducts the forecasts each spring with the option of second forecast in the winter if changing economic conditions warrant a new forecast. The results are fed into Avista’s revenue model, which converts the load forecast into a revenue forecast. In turn, the revenue forecast feeds Avista’s earnings model. In IRP years, the long-term forecast boot-straps off the five-year forecast by applying growth assumptions beyond year five. Overview of the Five-Year Retail Load Forecast The five-year retail load forecast is a two-step process. For most schedules in each class, there is a monthly use per customer (UPC) forecast and a monthly customer forecast.8
The load forecast is generated by 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(𝑘𝑊ℎ𝑡,𝑦𝑐+𝑗,𝑠) = 𝐹(𝑘𝑊ℎ/𝐶𝑡,𝑦𝑐+𝑗,𝑠) × 𝐹(𝐶𝑡,𝑦𝑐+𝑗,𝑠)

Where:
 F(kWht,yc+j,s) = the forecast for month t, year j = 1,…,5 beyond the
current year, yc ,for schedule s.
 F(kWh/Ct,yc+j,s) = the UPC forecast.
 F(Ct,yc+j,s) = the customer forecast.
8 For schedules representing a single customer, where there is no customer count and for street lighting, total load is forecast directly without first forecasting UPC.
2.3%
1.4%
2.3%
0.7%
1.6%
2.1%
2.3%2.4%
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 33 of 205
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/𝐶𝑡,𝑦,𝑠=𝛼𝑊𝑡,𝑦+ 𝛽𝑍𝑡,𝑦+ 𝜖𝑡,𝑦
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); 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 3.3 can be improved by converting it into an 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 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.
For certain schedules, such as those related to lighting, simpler regression and smoothing methods are used 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. Normal weather for the forecast is defined 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 when a full year of new data is available. For example, normal weather for 2015 is the 20-year average of degree-days for the 1995 to 2014 period; and 2016 is the 1996 to 2015 period.

9 Faruqui, Ahmad (2000). Making Forecasts and Weather Normalization Work Together, Electric Power Research Institute, Publication No. 1000546, Tech Review, March 2000.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 34 of 205
The choice of a 20-year moving average for defining normal weather reflects several
factors. First, recent climate research from the National Aeronautics and Space
Administration’s (NASA) Goddard Institute for Space Studies (GISS) shows a shift in temperature starting about 20 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 20 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 shows an upward shift in temperature starting about 20-years ago. A detailed discussion of this analysis is 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 function of the years used to calculate the average. Moving averages of ten and 15 years showed considerably more year-to-year volatility than the 20-year average.
This volatility can obscure longer-term trends and lead to overly sharp changes in forecasted loads when the updated definition of normal weather is applied each year. These sharp changes would also cause excessive volatility in the revenue and earnings
forecasts. As noted earlier, if RAP and IP appear in Equation 3.2, then they must also be in the forecast for five years to generate the UPC forecast. The assumption in the five-year forecast for this IRP is the RAP will increase two percent annually. This rate reflects the average annual real growth rate for the 2005-2013 period.
Table 3.1: UPC Models Using Non-Weather Driver Variables
Schedule Variables Comment Washington:
Residential Schedule 1 RAP
Commercial Schedule 31 RAP Commercial pumping schedule Industrial Schedule 31 RAP Industrial Schedules 11, 21, and 25 IP Idaho: Residential Schedule 1 RAP Commercial Schedule 31 RAP Commercial pumping schedule Industrial Schedules 11 and 21 IP
IP forecasts generate from a regression using the GDP forecast. Equation 3.3 and Figure 3.7 describes this process.

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.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 35 of 205
Equation 3.3: IP Regression Equation
𝐺𝐼𝑃𝑦,𝑈𝑆= 𝜈0 + 𝜈1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝜖𝑦
Where:
 GIPy,US = the annual growth in IP in year y.
 GGDPy,US = the annual growth in real GDP in year y.
 εy = a random error term. Equation 3.3 uses historical data and incorporates forecasts for GDP to forecast GIP over five years. GIP is an input for the generation of a forecast for the level of the IP index. The
forecasts for GGDP reflect the average of forecasts from multiple sources. Sources include 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 that macroeconomic factors flow through UPC in the industrial schedules. This reflects the relative stability of industrial customer growth over the business cycle.
Figure 3.8 shows the historical relationship between the IP and industrial load for electricity.11, The load values have been seasonally adjusted using the Census X12 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 3.7: Forecasting IP Growth

11 Data Source: U.S. Federal Reserve and Avista records.
12 Figure 3.8 excludes one large industrial customer with significant load volatility.
Growth Forecasts: IMF, FOMC, Bloomberg, etc. Average forecasts out 5-yrs.
Index (IP) Growth Model:
Model links year y GDP growth year y IP growth. Federal Reserve industrial production index is measure of IP growth.

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
GD
P IP
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 36 of 205
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 autoregressive integrated moving average (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 schedule customer counts, the dependent variable. Because the customer counts in most 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 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 users 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 Residential Schedule 1 customers become drivers to generate customer forecasts for Commercial Schedule 11 customers. Figure 3.9 shows the relationship between annual population growth and year-over-year customer growth.13 Customer growth has closely followed population growth in the
combined Spokane-Kootenai MSAs over the last 15 years. Population growth averaged 1.2% over the 2000-2016 period, and customer growth averaged 1.1 percent annually.
13 Data Source: Bureau of Economic Analysis, U.S. Census, Washington State OFM, and Avista records.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 37 of 205
Table 3.2: Customer Growth Correlations, January 2005 – December 2013
Customer Class (Year-over-Year) Residential Commercial Industrial Streetlights
Residential 1
Commercial 0.892 1
Industrial -0.285 -0.167 1
Streetlights -0.273 -0.245 0.209 1
Figure 3.9 demonstrates population growth can be used as a proxy for customer growth.
As a result, forecasted population is an adjustment to Expected Case forecasts of Residential Schedule 1 customers in Washington and Idaho. An Expected Case forecast is made using an ARIMA times-series model, for Schedule 1 in Washington and Idaho. If
the growth rates generated from this approach differ from forecasted population growth, the Expected Case forecasts are adjusted to match forecasted population growth. Figure 3.10 summarizes the forecasting process for population growth for use in Residential Schedule 1 customers. Figure 3.9: Population Growth vs. Customer Growth, 2000-2016

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 38 of 205
Figure 3.10: Forecasting Population Growth
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 forecasting models for regional employment growth are:
Equation 3.4: Spokane Employment Forecast
𝐺𝐸𝑀𝑃𝑦,𝑆𝑃𝐾= 𝜗0 + 𝜗1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝜗2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆+ 𝜗3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑆𝐶𝐷𝐾𝐶,1998−2000=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 + 𝜖𝑡,𝑦
Equation 3.5: Kootenai Employment Forecast
𝐺𝐸𝑀𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛿0 + 𝛿1𝐺𝐺𝐷𝑃𝑦,𝑈𝑆+ 𝛿2𝐺𝐺𝐷𝑃𝑦−1,𝑈𝑆
+ 𝛿3𝐺𝐺𝐷𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1+ 𝜔𝑂𝐿𝐷2009=1 + 𝜔𝑆𝐶𝐷𝐻𝐵,2005−2007=1 + 𝜖𝑡,𝑦

Where:
 SPK = the Spokane, WA MSA.
 KOOT = the Kootenai, ID MSA.
 GEMPy = employment growth in year y.
 GGDPy,US, GGDPy-1,US, and GGDPy-2,US = U.S. real GDP growth in years y, y-1,
and y-2.
 DKC = structural change (SC) dummy variables for the closing of Kaiser
Aluminum in Spokane.
 DHB = for the housing bubble, specific to each region.
 D1994=1 and D2009=1 = outlier (OL) dummy variables for 1994 and 2009 in
Kootenai.
 εy = a random error term.
Average GDP Growth Forecasts: IMF, FOMC, Bloomberg, etc. Average forecasts out 5-years.
Model links regional, U.S., and CA year y-1 employment growth to year y county population growth.
Forecast out 6-years for Spokane, WA; Kootenai, ID; and Jackson, OR.
Averaged with IHS forecasts in ID and OFM forecasts in WA.
Growth rates used to generate population forecasts for customer
Growth Model:
Model links year y, y-1, and y-2 GDP growth to year y regional employment growth.
Forecast out 6-years. Averaged with IHS
GDP
EMP
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 39 of 205
The same average GDP growth forecasts used for the IP growth forecasts are inputs to
the five-year employment growth forecast. Employment forecasts are averaged 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. The forecasting models for regional population growth are: Equation 3.6: Spokane Population Forecast
𝐺𝑃𝑂𝑃𝑦,𝑆𝑃𝐾= 𝜅0 + 𝜅1𝐺𝐸𝑀𝑃𝑦−1,𝑆𝑃𝐾+ 𝜅2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷2001=1+𝜖𝑡,𝑦
Equation 3.7: Kootenai Population Forecast

𝐺𝑃𝑂𝑃𝑦,𝐾𝑂𝑂𝑇= 𝛼0 + 𝛼1𝐺𝐸𝑀𝑃𝑦−1,𝐾𝑂𝑂𝑇
+ 𝛼2𝐺𝐸𝑀𝑃𝑦−2,𝑈𝑆+ 𝜔𝑂𝐿𝐷1994=1 + 𝜔𝑂𝐿𝐷2002=1+ 𝜔𝑆𝐶𝐷𝐻𝐵,2007↑=1 + 𝜖𝑡,𝑦

Where:
 SPK = the Spokane, Washington MSA.
 KOOT = the Kootenai, Idaho MSA.
 GPOPy = employment growth in year y.
 GEMPy-1 and GEMPy-2 = employment growth in y-1 and y-2.
 D1994=1, D2001=1, and D2002=1 = outlier (OL) dummy variables for recession
impacts
 DHB,2007=1 = structural change (SC) dummy variable that adjusts for the after
effects of the housing bubble collapse in the Kootenai, Idaho MSA.
Equations 3.6 and 3.7 are estimated using historical data. Next, the GEMP forecasts (the average of Avista and IHS forecasts) become inputs to Equations 3.6 and 3.7 to generate 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 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 five-year projection out to 2035. It includes the impacts from growing electric vehicle (EV) fleets and residential rooftop photovoltaic solar (PV). The long-run modeling approach starts with Equation 3.8.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 40 of 205
Equation 3.8: Residential Long-Run Forecast Relationship
ℓ𝑦= 𝑐𝑦+ 𝑢𝑦
Where:
 ℓy = residential load growth in year y.
 cy = residential customer growth in year y.
 uy = UPC growth in year y. Equation 3.8 sets annual residential load growth equal to annual customer growth plus the annual UPC growth.14 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 Expected Case forecast makes assumptions about the long-run relationship between residential, commercial, and industrial classes, as documented below. 1. Long-run residential and commercial customer growth rates are the same for 2022 to 2040, consistent with historical growth patterns over the past decade. Figure 3.11
shows the Expected Case time path of residential customer growth. The average annual growth rate after 2021 is approximately 0.8 percent, assuming a gradual decline starting in 2022. The values shown in Figure 3.11 were generated with the
Employment and Population forecast Equations 3.4, 3.5, 3.6, and 3.7 in conjunction with IHS’s employment and population forecasts and Washington’s OFM population forecasts. The annual industrial customer growth rate assumption is zero, matching historical patterns for the past decade. 2. Commercial load growth follows changes in residential load growth, but with a spread of 0.5 percent. This high correlation assumption is consistent with the high historical correlation between residential and commercial load growth. The 0.5 percent spread is within the range of historical norms and the forecasted growth spread from the five-year model.
3. Consistent with historical behavior, industrial and streetlight load growth projections are not correlated with residential or commercial load. Annual industrial load growth is
set at 0.5 percent and streetlight load growth at 0.1 percent for 2022-2037. Both growth rates are in the range of historical norms and forecasted growth trends from the five-year model. 4. The real residential price per kWh increases at 2 percent per year until 2027. Up to 2027, this is the same as the nominal price increasing 4 percent per year assuming a
14 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. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 41 of 205
non-energy inflation rate of 2 percent. The real price increase assumption is zero
starting in 2027. This assumption means the nominal price is increasing at the same rate as consumer inflation, excluding energy. This assumption relies on historical trends in residential prices and current capital spending plans.
5. The own-price elasticity of UPC is set at -0.11. Own price elasticity was estimated from the five-year UPC forecast equations for Residential Schedule 1 in Washington and Idaho. Specifically, the own-price elasticity calculation uses the customer-weighted average between Washington and Idaho. 6. From 2022 to 2024, depressed UPC growth results from new lighting and other
efficiency standards. The impact is more gradual than the Energy Information
Administration’s (EIA) modeling assumptions in its 2016 Annual Energy Outlook. The EIA assumes a large decline in UPC growth in 2020 with a subsequent sharp rebound
in 2021 that Avista believes is too volatile. 7. Electric vehicles (EVs) grow at a rate consistent with present adoption rates. Using
Electric Power Research Institute data, Avista estimates that as of 2015 there were around 400 EVs registered in its service area. The forecasted rate of adoption over the 2020-2040 period is a function of and EV forecast provided by Avista’s EV management team. This forecast reflects a low, middle, and, high forecast for EVs in our electric service area. The low forecast predicts 20,000 EVs by 2040; the middle predicts 70,000; and the high predicts 118,000. The final 2040 forecast used for the IRP weights the low forecast at 70 percent, the middle a 20 percent weight; and the
high with a 10 percent weight. Therefore, the IRP forecast for 2040 is 0.70 x 20,000 + 0.20 x 70,000 + 0.10 x 118,000 = 39,800 EVs. Between 2016 and 2040, the implied growth rate is 19 percent, which puts total EVs in 2037 as 22,395. The forecast
assumes each EV uses 2,500 kWh per year. 8. Rooftop PV penetration, measured as the share of PV residential customers to total
residential customers, continues to grow at present levels in the forecast. The average PV system is forecast at the current median of 5.0 kW (DC) and a 13 percent capacity factor, or about 5,578 kWh per year per customer. It assumed that this median system size will increase annually to 6.0 kW (DC) by 2040, or about 6,694 kWh per year per customer. This is equal to an annual growth rate in PV kWh of about 0.8 percent per year. In addition, the IRP assumes the penetration rate (share of residential customers) will follow the historical regression relationship between the historical
penetration rate in year t and the historical number of residential customers in year t for the 2008-2015 period. Using this relationship, residential PV penetration will increase from 0.09 percent in 2016 to about 0.42 percent in 2037. Residential solar
adoption in Avista’s service area continues at a very modest pace even though solar prices have fallen significantly and state subsidies for solar are still in place. One important factor restricting solar adoption in our service territory is the stable real price of residential electricity. Adjusting the average residential price for CPI inflation, less energy, shows that real prices have been largely flat since 2009. The IRP assumes the real price of residential power will continue to rise at a very modest pace which, in
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 42 of 205
turn, will keep solar adoption in line with the historical data used to forecast future
solar adoption. Clarity on federal energy policy would help make possible adjustments to the forecast now based on historical behavior alone. Figure 3.11: Long-Run Annual Residential Customer Growth
Native Load Scenarios with Low/High Economic Growth The high and low load scenarios use population growth Equations 3.6 and 3.7, holding U.S. employment growth constant at 1.1 percent, but varying MSA employment growth
at higher and lower levels to gauge the impacts on population growth and utility loads. See Table 3.3. The high/low range for service area employment growth reflects historical employment growth variability. Simulated population growth is a proxy for residential and
customer growth in the long-run forecast model, and produces the high and low native load forecasts shown in Figure 3.12. Table 3.3: High/Low Economic Growth Scenarios (2017-2037)
Economic Growth Annual U.S. Employment Growth (percent)
Annual Service Area Employment Growth (percent)
Annual Population Growth (percent)
Expected Case 1.1 1.3 0.9
High Growth 1.1 2.0 1.6
Low Growth 1.1 0.1 0.8

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 43 of 205
Figure 3.12: Average Megawatts, High/Low Economic Growth Scenarios
Table 3.4 is the average annual load growth rate over the 2017-2037 period. The low growth scenario predicts a slight load decline over 2022-2024 due to the impact of the phased-in efficiency standards discussed in Item 6 of the Expected Case’s assumptions listed above. Table 3.4: Load Growth for High/Low Economic Growth Scenarios (2018-2037)
Economic Growth Average Annual Native Load Growth (percent)
Expected Case 0.47
High Growth 0.82
Low Growth 0.19
Long-Run Forecast Residential Retail Sales Focusing on residential kWh sales, Figure 3.13 is the Expected Case 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 2016 Annual Energy Outlook. Both
Avista’s and EIA’s forecasts show positive UPC growth returning around 2035. The 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 reflects the impact of EVs.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 44 of 205
Figure 3.13: UPC Growth Forecast Comparison to EIA
Figure 3.14 shows the EIA and Expected Case residential load growth forecasts of
residential load growth. Avista’s forecast is higher in the 2015-2020 period, reflecting an assumption that service area population growth will be stronger than the U.S. average,
consistent with government and consultant’s forecasts for the far west and Rocky
Mountain regions where Avista’s service territory is located. Figure 3.14: Load Growth Comparison to EIA

-2.5%
-2.0%
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
20
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An
n
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a
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G
r
o
w
t
h
EIA Refrence Case Use Per Household Growth
UPC Growth, Base-Line with Renewables and EV/PHEVs
-2.0%
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
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7
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G
r
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h
EIA Purchased Residential Electricity Growth (Quad. BTU)
Expected Case's Load Growth
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 45 of 205
Monthly Peak Load Forecast Methodology
The Peak Load Regression Model The peak load forecast helps Avista determine the amount of resources necessary to
meet peak demand. In particular, Avista must build generation capacity to meet winter and summer peak periods. Looking forward, the highest peak loads are 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. On a planning basis where extreme weather is expected to occur in the winter, peak loads occur in the winter throughout the IRP timeframe. Equation 3.9 shows the current peak load regression model. Equation 3.9: Peak Load Regression Model
ℎ𝑀𝑊𝑑,𝑡,𝑦𝑛𝑒𝑡𝑝𝑒𝑎𝑘= 𝜆0 + 𝜆1𝐻𝐷𝐷𝑑,𝑡,𝑦+ 𝜆2(𝐻𝐷𝐷𝑑,𝑡,𝑦)2
+ 𝜆3𝐻𝐷𝐷𝑑−1,𝑡,𝑦+ 𝜆4𝐶𝐷𝐷𝑑,𝑡,𝑦 + 𝜆5𝐶𝐷𝐷𝑑,𝑡,𝑦𝐻𝐼𝐺𝐻+ 𝜆6𝐶𝐷𝐷𝑑−1,𝑡,𝑦+ 𝜙1𝐺𝐷𝑃𝑞(𝑡).𝑦−1
+ 𝜔𝑊𝐷𝐷𝑑,𝑡,𝑦+ 𝜔𝑆𝐷𝐷𝑡,𝑦+ 𝜔𝑂𝐿𝐷𝑀𝑎𝑟 2005=1 + 𝜔𝑂𝐿𝐷𝐹𝑒𝑏 2012=1 + 𝜔𝑂𝐿𝐷𝐽𝑎𝑛 2015=1
+ 𝜔𝑆𝐶𝐷𝑊𝑖𝑛𝑡𝑒𝑟 2016 + 𝜔𝑆𝐶𝐷𝑆𝑢𝑚𝑚𝑒𝑟 2016 + 𝜖𝑑,𝑡,𝑦

Where:
 hMWd,t,y
netpeak = 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.
 HDDd,t,y and CDDd,t,y = heating and cooling degree days the day before the
peak.
 (HDDd,t,y)2 = squared value of HDDd,t,y.HDDd−1,t,y and CDDd−1,t,y = heating and
cooling degree days the day before the peak.
 CDDd,t,yHIGH = maximum peak day temperature minus 65 degrees.15
 GDPq(t).y−1 = level of real GDP in quarter q covering month t in year y-1.
 ωWDDd,t,y = dummy vector indicating the peak’s day of week.
 ωSDDt,y = seasonal dummy vector indicating the month; and the other dummy
variables control for outliers in March 2005, February 2012, and January
2015.
 ωSDDWinter 2016 and ωSDDSummer 2016 = dummy variables to control for the extreme
La Nina effects on peak load.
 εd,t,y = uncorrelated N(0, σ) error term.
Generating Weather Normal Growth Rates Based on a GDP Driver Equation 3.9 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
15 This term provides a better model fit than the square of CDD.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 46 of 205
out N years by using forecasted levels of GDP as shown in Equation 3.3.16 All other
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(ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+1
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊),𝐹(ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+2
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊),…,𝐹(ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+𝑁
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊)}

For summer, this is defined as the forecasted series S:
𝑆 = {𝐹(ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+1𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆),𝐹(ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+2𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆),…,𝐹(ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+𝑁𝑊𝑁,𝑛𝑒𝑡 𝑝𝑒𝑎𝑘,𝑆)}
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.):
𝑊𝐺={𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+1𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊),𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+2𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊),…,𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+𝑁𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊)}

𝑆𝐺={𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+1
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆),𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+2
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆),…,𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+𝑁
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆) }

In Equation 3.10, 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. The following section describes this process. Simulated Extreme Weather Conditions with Historical Weather Data Equation 3.10 generates a series of simulated extreme peak load values for heating degree days. Equation 3.10: Peak Load Simulation Equation for Winter Months
ℎ𝑀𝑊̂𝑡,𝑦𝑊= 𝑎 + 𝜆1̂𝐻𝐷𝐷𝑡,𝑦,𝑀𝐼𝑁 + 𝜆2̂(𝐻𝐷𝐷𝑡,𝑦,𝑀𝐼𝑁 )2 𝑓𝑜𝑟 𝑡 = 𝐽𝑎𝑛,…,𝐷𝑒𝑐 𝑖𝑓 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔.𝑡𝑒𝑚𝑝
<65 𝑎𝑛𝑑 𝑦=1890,…,𝑦𝑐

Where:
 hMŴt,yW = 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.
16 Forecasted GDP is generated by applying the averaged GDP growth forecasts used for the employment and industrial production forecasts discussed previously.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 47 of 205
Similarly, the model for cooling degree days is:
Equation 3.11: Peak Load Simulation Equation for Summer Months
ℎ𝑀𝑊̂𝑡,𝑦𝑆= 𝑎 + 𝜆4̂𝐶𝐷𝐷𝑡,𝑦,𝑀𝐴𝑋 𝑓𝑜𝑟 𝑡 = 𝐽𝑎𝑛,…,𝐷𝑒𝑐 𝑖𝑓 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔. 𝑡𝑒𝑚𝑝 >65 𝑎𝑛𝑑 𝑦
=1890,…,𝑦𝑐

Where:
 hMŴt,yS = 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 3.10 and 3.11 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. The average for each month are shown by Equations 3.12 and 3.13. Equation 3.12: Current Year Peak Load for Winter Months

𝐹(ℎ𝑀𝑊𝑡,𝑦𝑐
𝑊)=1
(𝑦𝑐−1890)+ 1 ∑ℎ𝑀𝑊̂𝑡,𝑦𝑊𝑦𝑐
𝑦=1890
𝑓𝑜𝑟 𝑒𝑎𝑐ℎ ℎ𝑒𝑎𝑡𝑖𝑛𝑔 𝑚𝑜𝑛𝑡ℎ 𝑡
𝑤ℎ𝑒𝑟𝑒 𝑚𝑎𝑥𝑖𝑢𝑚 𝑎𝑣𝑔.𝑡𝑒𝑚𝑝 <65 Equation 3.13: Current Year Peak Load for Summer Months
𝐹(ℎ𝑀𝑊𝑡,𝑦𝑐
𝑆)=1
(𝑦𝑐−1890)+ 1 ∑ℎ𝑀𝑊̂𝑡,𝑦𝑆𝑦𝑐
𝑦=1890 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:
𝐹(ℎ𝑀𝑊𝑡,𝑦𝑐+1
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊) = 𝐹(ℎ𝑀𝑊𝑡,𝑦𝑐
𝑊) ∗ [1 + 𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+1𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑊)]

𝐹(ℎ𝑀𝑊𝑡,𝑦𝑐+1
𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆) = 𝐹(ℎ𝑀𝑊𝑡,𝑦𝑐
𝑆) ∗ [1 + 𝐹(𝐺ℎ𝑀𝑊𝑑𝑀𝐴𝑋,𝑡𝑀𝐴𝑋,𝑦𝑐+1𝑊𝑁,𝑛𝑒𝑡𝑝𝑒𝑎𝑘,𝑆)]
The peak load forecast is finalized when the loads of two large industrial customers excluded from the Equation 3.12 and 3.13 estimations are added back in.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 48 of 205
Table 3.5 shows estimated peak load growth rates with and without the two large
industrial customers. Figure 3.15 shows the forecasted time path of peak load out to 2040, and Figure 3.16 shows the high/low bounds based on a one-in-20 event (95 percent confidence interval) using the standard deviation of the simulated peak loads from
Equations 3.12 and 3.13. Table 3.5: Forecasted Winter and Summer Peak Growth, 2017-2037
Category Winter (Percent) Summer (Percent) Excluding Large Industrial Customers 0.42 0.46 Including Large Industrial Customers 0.38 0.42
Table 3.6 shows the summer peak is forecast to grow faster than the winter peak. Under current growth forecasts, the orange summer line in Figure 3.15 will converge with the blue winter line in approximately year 2100. Figure 3.16 shows that the winter high/low bound considerably larger than summer, and reflects a greater range of temperature anomalies in the winter months. Table 3.6 shows the energy and peak forecasts. Figure 3.15: Peak Load Forecast 2017-2037

1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
19
9
7
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9
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1
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3
3
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3
5
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3
7
Me
g
a
w
a
t
t
s
Winter Peak
Summer Peak
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 49 of 205
Figure 3.16: Peak Load Forecast with 1 in 20 High/Low Bounds, 2017-2037
Table 3.6: Energy and Peak Forecasts
Year Energy (aMW) Winter Peak (MW) Summer Peak (MW)
2018 1,087 1,690 1,616
2019 1,094 1,697 1,623 2020 1,101 1,703 1,630 2021 1,109 1,710 1,637
2022 1,109 1,716 1,643
2023 1,109 1,723 1,650 2024 1,108 1,729 1,657 2025 1,114 1,736 1,664
2026 1,120 1,743 1,671 2027 1,126 1,749 1,678 2028 1,132 1,756 1,685
2029 1,138 1,763 1,692
2030 1,144 1,770 1,699 2031 1,150 1,776 1,707 2032 1,156 1,783 1,714
2033 1,162 1,790 1,721
2034 1,169 1,797 1,728 2035 1,175 1,804 1,735
2036 1,182 1,811 1,743
2037 1,189 1,818 1,750
1,000
1,200
1,400
1,600
1,800
2,000
2,200
19
9
7
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9
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3
5
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3
7
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Winter- High Winter- Low
Summer- High Summer- Low
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 50 of 205
Extreme Temperature Analysis
The impact of temperature changes and the relevance of historical temperature data drives much of the recent load forecasting debates regarding peak load forecasts. To validate the use of historical temperatures in the peak load forecast, an analysis using the
same GISS methodology and reference periods referenced in the UPC forecast methodology section. In particular, using 1951-1980 as the reference period, Avista examined daily temperature anomalies using daily temperature data from the Spokane International Airport going back to 1947. The analysis focuses on the core summer months (June, July, and August) and winter months (December, January, and February). The GISS study only considers summer
months and found, in addition to an increase in the average temperature in the summer, the variance around the average increased. Specifically, the frequency of extreme temperature anomalies three or more standard deviations above the summer average
increased compared to the 1950-1981 reference period. In contrast, Avista’s analysis shows average temperature increases compared to the reference period, but there was no significant shift in the frequency of extreme temperature events. This finding supports
continued use of historical temperature extremes for peak load forecasting.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 51 of 205
4. Existing Supply Resources
Introduction & Highlights
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 partial ownership of two coal-fired units, five natural gas-fired projects, and a biomass plant. Avista purchases energy from several independent power producers (IPPs), including Palouse Wind, Rathdrum Power, and the City of Spokane.
Figure 4.1 shows Avista capacity and energy mixes. Winter capability is the share of total capability of each resource type the utility can rely upon to meet peak load absent outages. 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 supply in the peak winter months is hydroelectric at 51 percent, followed by natural gas. On an energy capability basis, natural gas-fired generation can produce more energy, at 43 percent, than hydroelectric at 38 percent,
because it is not constrained by fuel limitations. In any given year, the resource mix will change depending on streamflow conditions and market prices. Figure 4.1: 2018 Avista Capability & Energy Fuel Mix

Owned Hydro40%
Contracted Hydro11%
Natural Gas37%
Coal9%
Biomass & Wind3%
Winter Capability
Owned Hydro28%
Contracted Hydro10%
Natural Gas43%
Coal13%
Biomass & Wind6%
Annual Energy
Section Highlights
Hydroelectric represents about half of Avista’s winter generating capability.
fired plants represent the largest portion of Avista’s thermal
Six percent of Avista’s generating potential is biomass and wind.


Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 52 of 205
Avista reports its fuel mix annually in the Washington State Fuel Mix Disclosure. The
State calculates the resource mix used to serve load, rather than generation potential, by adding regional estimates for unassigned market purchases and Avista-owned generation minus environmental attributes from renewable energy credit (REC) sales.
Spokane River Hydroelectric Developments
Avista owns and operates six hydroelectric developments on the Spokane River. Five
operate under 50-year FERC operating licenses issued in June 2009. The sixth, Little Falls, operates under separate authorization from the U.S. Congress. 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 state of the facility. This capacity is often higher than the nameplate rating for hydroelectric developments because of plant upgrades and favorable head or
flow conditions. The nameplate, or installed capacity, is the 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 facility furthest upstream on the Spokane River. It is located several miles east of the Washington/Idaho border. It 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 nameplate unit with a 10.26-MW maximum capacity rating. Monroe Street Monroe Street was Avista’s first generation development. It began serving customers in 1890 in downtown Spokane near Riverfront Park. Rebuilt in 1992, the single generating unit has a 14.8-MW nameplate rating and a 15.0-MW maximum capacity rating.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 53 of 205
Monroe Street Development and Huntington Park, Downtown Spokane, WA 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.
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. 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 of on-peak capacity and have a 32.0 MW nameplate rating. Avista is
carrying out a series of upgrades to the Little Falls development. Much of the new electrical equipment and the installation of a new generator excitation system are complete. Projects include replacing station service equipment, updating the
powerhouse crane, and developing new control schemes and panels are complete. Work is now ongoing to replace generators, turbines, and unit protection and control systems on the four units will start.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 54 of 205
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. The plants operate under a FERC license through 2046. Both hydroelectric projects on the Clark
Fork River connect to the Avista transmission system. Noxon Rapids
The Noxon Rapids development includes four generators installed between 1959 and 1960, and a fifth unit entered service in 1977. Avista completed major turbine 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. Cabinet Gorge Cabinet Gorge started generating power in 1952 with two units, and added two
additional generators the following year. Upgrades to units 1 through 4 occurred in 1994, 2004, 2001, and 2007. The current maximum on-peak plant capacity is 270.5 MW; it has a nameplate rating of 265.2 MW.
Total Hydroelectric Generation
Avista’s hydroelectric plants have 1,080 MW of on-peak 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

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

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Thermal Resources
Avista owns seven thermal generation assets located across the Northwest. Based on IRP analyses, Avista expects each plant to continue operation through the 20-year IRP horizon. The resources provide dependable energy and capacity serving base- and
peak-load obligations. A summary of their capabilities is in Table 4.2. Table 4.2: Avista-Owned Thermal Resources
Colstrip 3 (15%) Colstrip, MT Coal 1984 111.0 111.0 123.5
Colstrip 4 (15%) Colstrip, MT Coal 1986 111.0 111.0 123.5
Rathdrum Rathdrum, ID Gas 1995 176.0 130.0 166.5
Northeast Spokane, WA Gas 1978 66.0 42.0 61.2
Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6
Coyote Springs 21 Boardman, OR Gas 2003 317.5 286.0 287.3
Kettle Falls Kettle Falls, WA Wood 1983 47.0 47.0 50.7
Kettle Falls CT2 Kettle Falls, WA Gas 2002 11.0 8.0 7.5
Colstrip Units 3 and 4 The Colstrip plant, located in eastern Montana, consists of four coal-fired steam plants connected to a double-circuit 500 kV BPA transmission line under a long-term wheeling
agreement. Talen Energy Corporation operates the facilities on behalf of the six owners. Avista has no ownership interest in Units 1 or 2, but 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 222.0 MW, and a nameplate rating of 247.0 MW. Rathdrum Rathdrum consists of two 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 capacity of 176.0 MW in the winter and 126.0 MW in the summer. The nameplate rating is 166.5 MW. Northeast
The Northeast plant, located in Spokane, has two aero-derivative simple-cycle CT units completed in 1978. It connects to Avista’s transmission system. The plant is capable of burning natural gas or fuel oil, but current air permits preclude the use of fuel oil. The
1 For purposes of long-term transmission reservation planning for bundled retail service to native load customers, replacement resources for Coyote Springs 2 is presumed and planned to be integrated via
Avista’s interconnection(s) to the Mid-Columbia region. 2 The Kettle Falls CT capacity quantities include output of the natural gas-fired turbine plus the benefit of
its steam to the main unit’s boiler.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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combined maximum capacity of the units is 68.0 MW in the winter and 42.0 MW in the
summer, with a nameplate rating of 61.2 MW. The plant permit limits run hours to 100 per year. Boulder Park The Boulder Park project entered service in the Spokane Valley in 2002 and connects directly to the Avista transmission system. The site uses six natural gas-fired internal combustion reciprocating engines to produce a combined maximum capacity and nameplate rating of 24.6 MW. 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; it has a
maximum capacity of 317.5 MW in the winter and 285 MW in the summer, with duct burners. The nameplate rating of the plant is 287.3 MW. In 2016, the Advanced Hot Gas Path is the latest upgrade to the plant increasing both the unit’s capacity and efficiency.
Kettle Falls Generation Station and Kettle Falls Combustion Turbine The Kettle Falls Generating Station, a woody biomass facility, 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 biomass steam plant uses waste wood products from area mills and forest slash, but can also burn natural gas. 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.
The wood-fired portion of the plant has a maximum capacity of 50.0 MW, and its nameplate rating is 50.7 MW. The plant typically operates between 45 and 47 MW because of fuel conditions that change depending on the moisture content of the fuel.
The plant’s capacity increases to 55.0 to 58.0 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 resource can be limited in the winter when the natural gas pipeline is capacity constrained. For IRP modeling, the CT does not run when temperatures fall below zero. This operational assumption reflects natural gas availability limits on the plant when local natural gas distribution demand is highest. Power Purchase and Sale Contracts
Avista uses purchase and sale arrangements of varying lengths to meet a portion of its load requirements. Contracts provide many benefits, including environmentally low-
impact and low-cost hydroelectric and wind power. This chapter describes the contracts in effect during the timeframe of the 2017 IRP. Tables 4.3 through 4.5 summarize
Avista’s contracts.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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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 then served by the PUDs. Long-term contracts with public,
municipal, and investor-owned utilities throughout the Northwest assisted with project financing and ensured 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 four of these projects
“at cost.” Avista now competes in capacity auctions to retain the rights of these expiring contracts. The Mid-Columbia contracts in Table 4.3 provide energy, capacity and reserve capabilities; in 2017, the contracts provide approximately 154 MW of capacity and 101 aMW of energy. Recently, Avista successfully negotiated an extension of the Chelan PUD contract. However, there are no guarantees to extend contract rights
beyond this term. Due to the uncertainty around future availability and cost, the IRP does not include these contracts in the resource mix beyond their current expiration dates. Avista was also able to extend its legacy Douglas PUD contract set to expire in
2018. The new contract provides capacity and energy through September 2028 at a decreasing portion each year until it expires. 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. On September 16, 2024, the Columbia River Treaty
may end. 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 soon negotiations will begin to determine the future of the treaty. This
IRP does not model alternative outcomes for the treaty negotiations, because it will not likely affect long-term resource acquisition and we cannot speculate on future wholesale electricity market impacts of the treaty. 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.
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Table 4.3: Mid-Columbia Capacity and Energy Contracts3
Counter Party Project(s) Percent Share (%)
Start Date End Date Estimated On-Peak Capability (MW)
Annual Energy (aMW)
Grant PUD Priest Rapids 3.7 Dec-2001 Dec-2052 34.8 19.5
Grant PUD Wanapum 3.7 Dec-2001 Dec-2052 34.5 18.7
Chelan PUD Rocky Reach 5.0 Jan-2016 Dec-2030 58.1 35.8
Chelan PUD Rock Island 5.0 Jan- 2016 Dec-2030 20.1 18.4
Douglas PUD Wells 3.34 Feb-1965 Sep-2028 27.9 14.3
Canadian Entitlement -10.1 -5.7
2018 Total Net Contracted Capacity and Energy 165.3 101.0
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 4.4. The IRP assumes renewal of these contracts after their current
terms end. Table 4.4: PURPA Agreements
Meyers Falls Hydro Kettle Falls, WA 12/2019 1.30 1.05
Spokane Waste to Energy Waste Spokane, WA 12/2017 18.00 16.00
Spokane County Digester Biomass Spokane, WA 8/2021 0.26 0.14
Plummer Saw Mill Wood Waste Plummer, ID 12/2019 5.80 4.00
Deep Creek Hydro Northpoint, WA 12/2017 0.41 0.23
Clark Fork Hydro Hydro Clark Fork, ID 12/2017 0.22 0.12
Upriver Dam5 Hydro Spokane, WA 12/2019 17.60 6.17
Big Sheep Creek Hydro Hydro Northpoint, WA 6/2021 1.40 0.79
Ford Hydro LP Hydro Weippe, ID 6/2022 1.41 0.39
John Day Hydro Hydro Lucille, ID 9/2022 0.90 0.25
Phillips Ranch Hydro Northpoint, WA n/a 0.02 0.01

3 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 4.3 are presumed and
planned to be integrated via Avista’s interconnection(s) to the Mid-Columbia region. 4 The share from Wells is dependent on Douglas PUD’s load growth.
5 Energy estimate is net of the city of Spokane’s pumping load.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Bonneville Power Administration – WNP-3 Settlement
Avista signed settlement agreements with BPA and Energy Northwest on September 17, 1985, ending its nuclear plant construction delay claims against both parties. The settlement provides an energy exchange through June 30, 2019, with an agreement to
reimburse Avista for WPPSS – Washington Nuclear Plant No. 3 (WNP-3) preservation costs and an irrevocable offer of WNP-3 capability under the Regional Power Act. The energy exchange portion of the settlement contains two basic provisions. The first provision provides approximately 42 aMW of energy to Avista from BPA through 2019, subject to a contract minimum of 5.8 million megawatt-hours. Avista is obligated to pay BPA operating and maintenance costs associated with the energy exchange as
determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987-year constant dollars. The second provision provides BPA approximately 32 aMW of return energy at a cost equal to the actual operating cost of Avista’s highest-cost resource. A
discussion of this obligation, and how Avista plans for it, is in Chapter 6. Palouse Wind – Power Purchase Agreement
Avista signed a 30-year power purchase agreement in 2011 with Palouse Wind for the entire output of its 105-MW project. Avista has the option to purchase the project after 10 years. Commercial operation began in December 2012. The project is EIA-qualified
and directly connected to Avista’s transmission system. Table 4.5: Other Contractual Rights and Obligations
Contract Type Fuel Source End Date Winter Capacity (MW)
Summer Capacity (MW)
Annual Energy (aMW)
Douglas Settlement Purchase Hydro 9/2018 2 2 3 Energy America Sale CEC RECs6 12/2019 50 50 50 WNP-3 Purchase System 6/2019 82 0 42
Lancaster Purchase Natural Gas 10/2026 283 233 218
Palouse Wind Purchase Wind 12/2042 0 0 40
Nichols Pumping Sale System n/a -1 -1 -1
Total 416 284 352
Customer-Owned Generation
A small but growing number of customers install their own generation systems. In 2007 and 2008, the average number of new net-metering customers added was 10 yearly; and between 2009 and 2014, the average is 41 per year, but over the last two years, an increasing amount, 76 in 2015, and 112 in 2016. The recent increase likely driven by solar price reductions and the near term expiring of the generous federal and new state
tax incentives. Certain renewable projects qualify for the federal government’s 30 percent tax credit and Washington tax incentives of up to $5,000 per year through July
6 CEC RECs are renewable resources based on approval of the California Energy Commission. Kettle Falls, Palouse Wind, Nine Mile Falls, Post Falls, Monroe Street, and Upper Falls are CEC certified.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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2020. The Washington utility taxes credit finances these incentives that rise to as much
as $1.08 per kWh. Avista had 490 customer-installed net-metered generation projects on its system in
early June 2017 representing a total installed capacity of 3.5 MW. Eighty-eight percent of installations are in Washington, with most located in Spokane County. Figure 4.2 shows annual net metering customer additions through 2016. Solar is the primary net metered technology; the remaining is a mix of wind, combined solar and wind systems, and biogas. The average annual capacity factor of the solar facilities is 13 percent. Small wind turbines typically produce at less than a 10 percent capacity factor, depending on location. Given the current tax incentives when the IRP modeling occurred were nearing optimal payback, the number of new net-metered systems rose significantly in 2016. The signature of SB 5939 on July 7, 2017 established a new solar incentive program from October 1, 2017 through 2029 at a lower rate than the current
subsidy. If the number of net-metering customers continues to increase, Avista may need to adjust rate structures for customers who rely on the utility’s infrastructure, but do not contribute financially for infrastructure costs.
Figure 4.2: Avista’s Net Metering Customers

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Solar
As solar equipment and installation prices have decreased, the nation’s interest and development of the technology has increased dramatically. Avista has three small projects of its own and is working with a developer to construct a fourth. The first was
three kilowatts on its corporate headquarters as part of the Solar Car initiative. The solar production helped power two electric vehicles in the corporate fleet. Avista installed a 15-kilowatt solar system in Rathdrum, Idaho to supply Buck-A-Block, a voluntary
program allowing customers to purchase green energy. The 423-kW Avista Community Solar project entered service in 2015. The project takes advantage of federal and state subsidies. The $1,080/MWh Washington solar subsidy allows customers to purchase individual solar panels within the facility and receive payments that more than offset their upfront investment. The program utilizes approximately $600,000 each year in state tax incentives. SB 5939, signed by Governor Inslee on July 7, 2017, updates the solar incentive program for residential, commercial and shared commercial projects starting on or after October 1, 2017. The new solar program pays an incentive for eight years with projects starting later receiving a smaller incentive.
In April 2017, the company released a Request for Proposals to develop up to a 15 MW (DC) solar facility for the company’s new Solar Select Program. This project will voluntarily allow commercial and industrial customers to assign the solar costs and
production of the facility to their bill as a substitute for the utility’s regular power supply cost. The participating customer will continue to pay their regular bill, but get a rate
credit for the variable power supply portion of their rate and then substitute a “lock-in” solar rate for up to 20 years and the rate will not increase beyond its rate schedule for the term. This new rate schedule once approved by state Commissions will allow participating customers to acquire renewable energy and hedge power supply costs from future increases. Avista plans to file this tariff by the end of 2017.

Boulder Park Community Solar Project

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 63 of 205
5. Energy Efficiency & Demand Response
Introduction
Avista began offering energy efficiency programs to its customers in 1978. These programs pursue all cost-effective energy efficiency and operate within the prevailing market and economic conditions. Recent programs with the highest impacts on energy savings include residential and non-residential prescriptive lighting, residential fuel efficiency, site-specific lighting, and small business projects. In addition, the Oracle (formerly Opower) Home Energy Report program began sending peer-comparison reports to participating customers every two months beginning in June 2013. Conservation programs regularly meet or exceed regional shares of the energy efficiency gains outlined by the Northwest Power and Conservation Council (NPCC).

Figure 5.1 illustrates Avista’s historical electricity conservation acquisitions. Avista has
acquired 219 aMW of energy efficiency since 1978; however, the 18-year average measure life of the conservation portfolio means some measures no longer are reducing load. The 18-year measure life accounts for the difference between the cumulative and
online trajectories in Figure 5.1. Currently 145 aMW of conservation serves customers, representing nearly 12.3 percent of 2016 load. Avista energy efficiency programs provide conservation and education options to the residential, low income, commercial, and industrial customer segments. Program delivery includes prescriptive, site-specific, regional, upstream, behavioral, market transformation, and third-party direct install options. Prescriptive programs, or standard offerings, provide cash incentives for standardized products such as the installation of qualifying high-efficiency heating equipment. Prescriptive programs work 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 programs, or customized offerings, provide cash incentives for any cost-effective energy saving measure or equipment with an economic payback greater than one year and less than eight years for non-LED lighting projects, or less than 13 years for
Section Highlights
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all other end uses and technologies. Other delivery methods build off these approaches
but may include upstream buy downs of low cost measures, free-to-customer direct install programs, and coordination with regional entities for market transformation efforts. Figure 5.1: Historical Conservation Acquisition (system)
Efficiency programs with economic paybacks of less than one year are not eligible for incentives, although Avista assists in educating and informing customers about these types of efficiency measures. Site-specific programs require customized services for commercial and industrial customers because of the unique characteristics of each of their premises and processes. In some cases, Avista uses a prescriptive approach where similar applications of energy efficiency measures result in reasonably consistent savings estimates in conjunction with a high achievable savings potential. An example is prescriptive lighting for commercial and industrial applications.
The Conservation Potential Assessment Avista retained Applied Energy Group (AEG) as an independent third party to assist in developing a Conservation Potential Assessment (CPA) for this IRP. The study forms the basis for the conservation portion of this plan. The CPA identifies the 20-year potential
for energy efficiency and provides data on resources specific to Avista’s service territory for use in the resource selection process in the PRiSM model, in accordance with the
EIA’s energy efficiency goals. The energy efficiency potential 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. AEG implemented several changes to its current study including a regionally specific
categorization of savings potential. In the 2015 IRP, AEG provided three levels of
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Schedule 9, Page 65 of 205
potential: technical, economic, and achievable. This approach first considered the
economic screening of measures in the CPA then applied ramp rates in order to arrive at the achievable potential. For the 2015 plan, Avista compared using this methodology versus its new methodology utilizing a technical and achievable technical approach and
using PRiSM to select measures. Both methodologies arrived at similar results in the 2015 study, but the inclusion in the PRiSM model allows conservation to dynamically reduce portfolio risk. In the 2015 IRP Washington acknowledgement, Washington agreed Avista should make the methodology change. In the new method, AEG first develops estimates of technical potential, reflecting the adoption of all conservation measures, regardless of cost-effectiveness. Achievable Technical Potential modifies the technical potential by accounting for customer adoption constraints, using the Council’s Seventh
Plan ramp rates. The estimated achievable technical potential for each individual measure, along with associated costs, feed into the PRiSM model to select the cost-effective measures on a measure-by-measure basis rather than by bundling. AEG took
the following steps to assess and analyze energy efficiency and potential within Avista’s service territory. Figure 5.2 illustrates the steps of the analysis. Figure 5.2: Analysis Approach Overview
1. Characterize the Market: Categorizes energy consumption in the residential (including low-income customers), commercial, and industrial sectors. This assessment uses utility and secondary data to characterize customers’ electricity
usage behavior in Avista’s service territory. AEG uses this assessment to develop energy market profiles describing energy consumption by market segment, vintage
(existing or new construction), end use, and technology.
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2. Baseline Projection: Develops a projection of energy and demand for electricity,
absent the effects of future conservation by sector and by end use for the entire 20-year study.
3. Measure Assessment: Identifies and characterizes energy efficiency measures appropriate for Avista, including regional savings from energy efficiency measures acquired through Northwest Energy Efficiency Alliance efforts.
4. Potential: Analyzes measures to identify technical and achievable technical conservation potential.
Market Segmentation The CPA divides Avista customers by state and class. The residential class segments include single-family, multi-family, manufactured home, and low-income customers.1 AEG incorporated information from the Commercial Building Stock Assessment to break out the commercial sector by building type. Avista analyzed the industrial sector as a whole
for each state. AEG characterized energy use by end use within each 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 the “business as usual” metric without future utility conservation 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 2016 when the study began. Codes and standards have direct bearing on the amount of energy efficiency potential existing beyond the impact of these efforts. The baseline projection accounts for market changes including:
 customer and market growth;
 income growth;
 retail rates forecasts;
 trends in end use and technology saturations;
 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 Seventh Power Plan, the Regional Technical Forum, and other measures applicable to Avista. The 3,400 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.
1 The low-income threshold for this study is 200 percent of the federal poverty level. Low-income information is available from census data and the American Community Survey data.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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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. Many measures initially do not pass the economic screen of supply side resource options, but some
measures may become part of the energy efficiency program as contributing factors evolve during the 20-year planning horizon. Avista supplements energy efficiency activities by including potentials for distribution efficiency measures consistent with EIA conservation targets and the NPCC Seventh Power Plan. Details about the distribution efficiency projects are in Chapter 8 – Transmission and Distribution Planning.
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 the most credible and comprehensive national industry standard practice for specifying energy efficiency potential. Specifically, two types of potential are in this study, as discussed
below. Table 5.1 shows the CPA results for technical and achievable technical potential.
Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years)
2018 2019 2022 2027 2037
Cumulative (GWh)
Achievable Technical Potential 88.0 186.8 468.3 927.1 1,516.3
Technical Potential 190.1 376.7 771.7 1,370.9 1,937.0

Cumulative (aMW) Achievable Technical Potential 10.0 21.3 53.5 105.8 173.1 Technical Potential 21.7 43.0 88.1 156.5 221.1

Technical Potential Technical potential finds the most energy-efficient option commercially available for each purchase decision regardless of its cost. This theoretical case provides the broadest and highest definition of savings potential because it quantifies savings if all current equipment, processes, and practices in all market sectors were replaced by the most efficient and feasible technology. Technical potential in the CPA is a “phased-in technical potential,” meaning only the current equipment stock at the end of its
useful life is considered and changed out with the most efficient measures available. Non-equipment measures, such as controls and other devices (e.g., programmable thermostats) phase-in over time, just like the equipment measures.
Achievable Technical Potential Achievable Technical Potential is a subset of technical potential representing the portion of technically feasible reductions in load associated with applicable end-uses.
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.
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It refines technical potential by applying customer participation rates to account for
market barriers, customer awareness and attitudes, program maturity, and other factors that may affect market penetration of efficiency measures. The customer participation rates use the NPCC Seventh Plan ramp rates. PRiSM Co-Optimization
Avista’s identifies achievable economic conservation potential by concurrently evaluating supply side and over 8,700 demand side resources in PRiSM. This methodology was the result of a 2013 IRP Action Item to streamline the process of selecting conservation in conjunction with the Efficient Frontier. The 2015 IRP tested this method by comparing the traditional methodology with the co-optimization. The co-optimization resulted in similar
savings, and portfolios further down the Efficient Frontier selected additional energy efficiency to reduce risk at a higher cost. The Washington 2015 IRP acknowledgement asked Avista to make this change for the 2017 IRP. Now in PRiSM, the individual energy
efficiency resources compete with supply- and demand response options to meet resource deficits, although, energy efficiency measures benefit by receiving 10 percent more value compared to the supply-side resources. This methodology does not change the amount of conservation selected in the PRS, but provides information regarding conservation selection if Avista choses different portfolios in the Efficient Frontier analysis or other scenario analysis. Each program’s winter and summer peak contribution (including line loss benefit), plus the value of its energy savings are considered. Figure 5.3 shows the combined Washington and Idaho CPA for 2018 through 2037.3 Figure 5.3: Achievable Conservation Potential Assessment (20-Year Cumulative)

3 The achievable conservation does not include savings from T&D losses. Chapter 11 conservation totals include losses.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
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Conservation Targets
The IRP process provides conservation targets for the Washington EIA Biennial Conservation Plan. Other components, including conservation from distribution and transmission efficiency improvements, combine with energy efficiency targets to arrive at
the full Biennial Conservation Plan target for Washington. 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 5.4: Washington Annual Achievable Potential Energy Efficiency (Megawatt Hours)
For the 2018-2019 CPA, the two-year achievable potential is 69,899 MWh for Washington
Electric operations. The pro rata share of the utility’s ten-year conservation potential of
73,636 MWh is the basis for calculating the biennial target. Table 5.2 contains achievable conservation potential for 2018-2019 using the PRiSM methodology. In addition to traditional efficiency programs, Avista is replacing approximately 21,640 high-pressure sodium fixtures in Washington and Idaho with comparable LED fixtures. The expected completion of this project is late 2019; efficiency savings are not available at this time to include in the achievable target. Also included is the energy savings from feeder upgrade projects. These projects, described in Chapter 8 – Transmission and Distribution Planning, reduce system losses.

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
PRiSM 32,394 69,899 103,108 141,532 181,537 219,967 256,765 296,068 332,472 368,181
10-yr Prorata 36,818 73,636 110,454 147,272 184,091 220,909 257,727 294,545 331,363 368,181
32,394
69,899
368,181
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Schedule 9, Page 70 of 205
Table 5.2: Annual Achievable Potential Energy Efficiency (Megawatt Hours)
2018-2019 Biennial Conservation Target Savings (MWh)
Pro Rata Share of CPA 73,636
Behavioral Program 15,386
Less: NEEA (21,812)
End-Use Efficiency Measures Subtotal 67,210 Plus: Distribution Efficiency 714 Plus: Generation Efficiency 151 Total 68,075 Plus: Decoupling Commitment 3,404 Proposed Biennial Conservation Target + Decoupling (EIA) (Subject to Penalties) 71,479 Plus: NEEA Projection 21,812 Total Conservation Commitment 93,291
Table 5.3: Annual Achievable Potential Energy Efficiency (Megawatt Hours)
2018 Feeder Upgrades 233 TBD 233
2019 Feeder Upgrades 481 472 953

2018 LED Street Lighting TBD TBD TBD
2019 LED Street Lighting TBD TBD TBD

2018 Facility Efficiencies 0 300 300
2019 Facility Efficiencies 151 0 151
For conservation efforts in Idaho, the Idaho Public Utilities Commission asked Avista to pursue cost effective measures and set conservation goals based on the Utility Cost Test (UCT). While the conservation identified in this IRP uses the Total Resource Cost (TRC) in terms of power planning over twenty years, the amount of conservation the Company
will pursue in Idaho beginning in 2018 will use the UCT. Using the UCT as the basis for conservation, Avista identifies achievable potential
conservation in Idaho of 15,370 MWh in 2018. The company determined this savings amount by applying an adjustment factor of 1.28 to Avista’s TRC goal of 12,008 MWh. The 1.28 adjustment factor is the ratio of the TRC to the UCT from the Company’s 2016 Idaho DSM Annual Report. In this report, Avista obtained a TRC of 2.13 and a UCT of 2.73 with the UCT being 1.28 times higher than the TRC.
NPCC’s Seventh Power Plan Benchmarking
Figure 5.5 illustrates the comparison between Avista’s CPA Achievable Conservation and its estimated allocation of the Seventh Power Plan’s regional savings. Commercial and
Industrial sectors have been combined into a single category titled “non-residential.”
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 71 of 205
It is important to note that the value for from the Seventh Power Plan represents a single
point within a range of values. The comparison relies on the assumption that Avista’s share of the region is 3.5 percent (Sixth Power Plan assumption). A 0.5 percent variance
in this allocation would increase or decrease Avista’s allocation of the Seventh Power
Plan by approximately 12 aMW.
Comparing Avista’s CPA to the Seventh Power Plan The Washington 2015 IRP acknowledgement asked Avista to compare its IRP conservation and demand response (DR) results to the Seventh Power Plan. Avista’s Washington Electric CPA identifies 42 aMW of savings for the 2018-2027 period with 13 aMW from Residential and 29 aMW from Non-Residential saving. Avista’s allocation of the Seventh Power Plan’s regional savings is approximately 61 aMW, with 24 aMW from Residential and 37 aMW from Non-Residential. See Figure 5.5.
The comparison of Avista’s CPA and its share of the Seventh Power Plan considers several factors. Avista’s avoided cost is lower than the costs used to calculate average regional energy costs. Because avoided cost is a primary factor in determining cost-
effectiveness, some regional portfolio measures are not cost effective in Avista’s CPA. Avista calculated the 61 aMW using the highest Levelized Cost Bins for Conservation4. While information that is more granular is available, complications exist depending on end use customers and the type of individual measures considered. For consistency, the comparison uses the highest Cost Bin in calculating Avista’s share of the Seventh Power Plan. This approach provides the most conservative estimates on cost.
Figure 5.5: 2017 Avista CPA / Seventh Power Plan Benchmark Comparison

4 Seventh Power Plan Appendix G, Table G-7: Levelized Cost Bins for Conservation.
13
29
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Schedule 9, Page 72 of 205
Consistency with the Seventh Power Plan
AEG’s methodology to develop the electric CPA is consistent with the Council’s Seventh Power Plan methodology and fulfills the requirements of the utility analysis option as specified in WAC 194-37-070 subsection (6),(a)(i) through (xv).5 This CPA, like the
Seventh Plan, uses an end-use model to distinctly consider and account for the following:
 Building characteristics that reflect Avista’s service territory;
 Fuel and equipment saturations based on the knowledge of Avista’s customers;
 Measure life;
 Stock accounting;
 Existing and new construction;
 Lost-and non-lost opportunities;
 Measure saturation and applicability;
 Measure savings, including contribution to system peak;
 Customer growth; and
 Federal and state standards for appliances and technologies. Like the Seventh Plan, the Avista CPA uses a frozen-efficiency approach assuming equipment efficiency purchase decisions are fixed, with the exception of changes due to the phase-in of new codes and standards.
For this CPA, AEG develops estimates of Technical Potential and Achievable Technical Potential.6 The Economic Achievable Potential was determined by running the Achievable
Technical Potential through PRiSM. The Power Act’s 10 percent adder for conservation is added to the avoided energy costs within the PRiSM model. In terms of conservation measures, the CPA includes all measures incorporated in the Seventh Plan, as well as additional measures. However, the CPA analyzes each measure individually, whereas the Seventh Plan bundles measures in some cases. All measures were characterized using data from the Seventh Plan and RTF workbooks, when
available. If a measure was not characterized using the Seventh Plan or RTF workbooks, AEG relied upon its database of energy efficiency measures (DEEM) that is developed by incorporating measures encountered throughout the country and characterized using
sources typically cited by the NPCC in its analyses. Similar to the Council’s approach, AEG removes measures with market saturation, such as LED TVs, while at the same time includes and updates commercially available technologies.

To develop Technical Potential, AEG’s LoadMAP model includes all technically feasible potential conservation. The model choses the most efficient option at the time of equipment turnover. The market acceptance rates used to develop Achievable Technical potential are based upon the new, simplified Seventh Plan ramp rates. AEG mapped each of the individual measures to a Seventh Plan ramp rate and compared the results to historical achievements. AEG then adjusted the 2018 achievable technical potential for
5 http://apps.leg.wa.gov/WAC/default.aspx?cite=194-37&full=true 6 AEG provided estimates of Technical Potential, Economic Potential, and Achievable Potential in previous CPAs. For this study, the ramp rates were applied to the Technical Potential and provided to Avista to run through PRiSM to estimate the cost-effective conservation potential.
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those specific measures to line up with 2018. This provided a starting point for 2018
potential aligned to historic results. AEG provided the individual measure characteristics at the Achievable Technical level to Avista to run through PRiSM to determine which measures are cost-effective and included in the Economic Achievable Potential or targets.
Energy Efficiency-Related Financial Impacts
The EIA requires utilities with over 25,000 customers to obtain a fixed percentage of their
electricity from qualifying renewable resources and acquire all cost-effective and achievable energy conservation.7 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 Washington 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 2018 conservation acquisition cost to electric customers is $14.5 million. This amount grows by 200% to $29 million by 2027, a total of $214 million over this 10-year
period. Costs continue increasing after 2027 to more than $40 million in 2037.
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 the results are not detailed enough to form an actionable plan. Avista uses both
processes’ results to establish a budget for energy efficiency measures, help determine
the size and skill sets necessary for future operations, and identify general target markets for energy efficiency programs. This section provides an overview of recent operations of the individual sectors, as well as energy efficiency business planning.
The CPA is useful 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 TRC benefit-cost ratios, resulting in the lowest cost resources, brings the greatest amount of benefits to the overall portfolio.
 By identifying measures with great adoption barriers based on the economic versus achievable results by measure, staff can develop effective programs for measures with slow adoption or significant barriers.
 By improving the design of current program offerings, staff can review the measure level results by sector and compare the savings with the largest-saving measures currently offered. This analysis may lead to the addition or elimination of programs.
7 The EIA defines cost effective as 10 percent higher than the cost a utility would otherwise spend on energy acquisition.
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Additional consideration for lost opportunities can lead to offering greater
incentives on measures with higher benefits and lower incentives on measures with lower benefits.
The CPA illustrates potential markets and provides a list of cost-effective measures to
analyze through the on-going energy efficiency business planning process. This review of both residential and non-residential program concepts, and their sensitivity to more detailed assumptions, feeds into program planning. Residential Sector Overview
The Company’s residential portfolio is composed of several approaches to engage and encourage customers to consider energy efficiency improvements within their home. Prescriptive rebate programs are the main component of the portfolio, but augment variety of other interventions. These include: upstream buy-down of low-cost lighting and water saving measures, select distribution of low-cost lighting and weatherization
materials, direct-install programs and a multi-faceted, multichannel outreach and customer engagement effort.
Washington and Idaho residential customers received over $10.2 million in rebates to offset the cost of implementing these energy efficiency measures. All programs within the residential portfolio contributed over 83,400 MWh and over 669,800 therms to the 2016 annual energy savings. Avista launched a Home Energy Reports program in June 2013, targeting 73,501 Idaho and Washington customers with high electric use. As of December 2015, Avista had 48,800 customers still in the Home Energy Reports program. In January of 2016, Avista
‘refilled’ their existing Home Energy Reports Program by 24,706 customers bringing total distribution to approximately 73,506 electric customers in Idaho and Washington.
Eligibility for treatment includes several criteria such as sufficient (two year) billing history,
enough peers to build comparison group, not in the control group, not a ‘do not solicit’ customer and high enough electric use to be cost-effectively treated. In an effort to reduce
energy usage through behavioral changes, Home Energy Reports show personalized usage insights and energy saving tips. Customers also see a ranking of similar homes, comparison to themselves and a personal savings goal on the Reports. In addition to closely matching usage curves, the similar home comparisons use the following four criteria: square footage, home type, heat type and proximity. The Oracle Home Energy Report contributed 12,131 MWh of savings in 2016.
Low-Income Sector Overview The Company leverages the infrastructure of six network Community Action Program (CAP) agencies and one tribal weatherization organization to deliver energy efficiency
programs for the Company’s low-income residential customers in the Washington service territory. CAP agencies have resources to income qualify, prioritize and treat client homes
based upon a number of characteristics. In addition to the Company’s annual funding, the agencies have other monetary resources to leverage when treating a home with weatherization or other energy efficiency measures. The agencies either have in‐house or contract crews to install many of the efficiency measures of the program. The low-
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income energy efficiency programs contributed 830 MWh of electricity savings and
19,183 therms of natural gas savings in 2016 to Avista’s system. The general outreach programs provide energy management information and resources at events (such as resource fairs) and through partnerships to reach target populations. These programs also include bill payment options and assistance resources in senior and low-income publications. In 2016, Avista participated in 193 events in Idaho and Washington including workshops, energy fairs, mobile outreach events, and general outreach partnerships and events reaching over 16,500 individuals. Non-Residential Sector Overview
The non-residential energy efficiency market delivers through a combination of prescriptive and site-specific offerings. Any measure not offered through a prescriptive program is automatically eligible for treatment 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. In 2016, more than 2,900 prescriptive and site-specific nonresidential projects received funding. Additionally, the Small Business program installed over 27,500 measures. Avista contributed more than $14.8 million for energy efficiency upgrades in nonresidential and small business applications. Non-residential programs realized over 73,900 MWh and 196,875 therms in annual first‐year energy savings.
Program changes made at the beginning of 2016 to the non-residential programs include the addition of new program offerings and changes to eligibility or incentive levels. Avista communicates the majority of program changes after the Business Plan is final and the changes become effective at the beginning of the year. In addition, some program’s change throughout the year as necessary but these are less typical. For non-residential programs, changes effective January 1, 2016 to rebates reflect new
information regarding new unit energy savings (UES) and cost values. Avista accepted rebate applications through March 31, 2016 for 2015 measures and amounts. This 90-day grace period allows for a smooth transition when rebate programs change to allow
enough time for customers in the pipeline to complete their projects yet close out changes in a timely but balanced approach. After years of review, Avista began converting a large portion of its high-pressure sodium (HPS) street light system to LED units in 2015. Advancements in LED technology and lower product costs make early replacements cost effective. LEDs consume about half of the energy as their conventional counterparts for the same light output. Other non-energy benefits include improved visibility and color rendering relative to HPS lighting, and longer product life. The initial focus of the program is replacing 26,000 100-watt cobra-head style streetlights.
Conservation’s T&D Deferral Analysis Cost-effective energy efficiency programs require a review of cost versus its potential benefits. One benefit is the generation and delivery system investments avoided or
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deferred. Generation avoided investments are fairly 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 be reduced by energy efficiency due to the thermal limitations of the system. Utilities use a number of methods to estimate avoided T&D costs and there is no one
“best” approach to developing these estimates. There is a wide range of estimates for avoided T&D, underscoring the diverse nature of the methods used to calculate avoided costs. For the past several IRPs, Avista used $10 per kW-yr (2006 dollars), based on a study for the 2007 IRP, this out of date study is driving the need for a new methodology as part of the 2015 IRP action plan.
For this IRP, Avista chose to value these benefits using the current values approach. The current values approach considers the amount of current investment in both T&D from a
revenue requirement reference point, then divided by the peak load of the system, to estimate a $/kW-yr. value (see Table 5.2). This method’s strength is its simplicity, lending itself to frequent updates, but does not accurately portray the amount of deferred future
T&D investment due to new conservation programs. Avista will consider moving to another methodology to account for this benefit in the next IRP. Further, in Chapter 8,
there is a discussion of a storage facility’s benefit to the distribution system by deferring new capital investment using three feeders as case studies. Given, T&D deferments importance, Avista will evaluate alternative methods to value these benefits to future investment. Table 5.4: Transmission and Distribution Benefit

Transmission Net Book Value Distribution Net Book Vale
Washington $294,988,593 $675,072,411
Idaho $153,799,772 $348,486,297 Total $448,788,365 $1,023,558,708
Revenue Requirement $448,859,497 $1,099,186,748

Peak Load (MW) 1,693 1,693
Current $/kW $265 $649
Levelized Cost $13.77 $15.95
Total Levelized cost $29.72 Generation Efficiency Audits of Avista Facilities
Avista engineers performed energy efficiency audits at all of Avista’s hydroelectric dams
and most of thermal generation facilities where Avista wholly owns or is a partial owner, excluding Colstrip Generating station in Colstrip, Montana. The scoping audits focused on lighting, shell, HVAC and motor controls on processes. Table 5.5 shows efficiency potential and Table 5.6 shows the efficiency projects for Avista generation facilities planned for 2017 and 2018.
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Table 5.5: Preliminary Generation Facility Efficiency Upgrade Potential
Facility Description Measure Life (years)
Electric Savings (kWh)
Boulder Park
Control Room Lighting 15 3,931
Generating Floor Lighting High Bays 15 16,099
Replacing Engine Bay Lights 15 6,736
Replace Exterior Wall Packs 15 16,054
Instrument Air Cycling Air-Dryers 12 10,074
Oil Reservoir Heater Fuel Conversion8 15 525,600
Coyote Springs
Control Room Lighting 15 6,368
Generating Floor Lighting High Bays 15 85,778 Roadway Lighting 15 1,085 Air-Compressor VFD 12 130,000 Retrofit Air-Dryer with Dew-Point Controls 12 25,000 Kettle Falls

Plant Lighting 15 150,190
Plant Lighting Controls 15 183,058
Yard Lighting 15 48,180
Forced Draft Boiler Fan VSD 12 700,000
Little Falls Speed Controls Cooling/Exhaust Fans 12 247,909
Long Lake Variable Speed Stator Cooling Blowers 12 135,000
Exterior Wall Packs 15 2,084
Northeast CT Halogen Pole Lights 15 5,146
Noxon Rapids Full LED Lighting Upgrade (Completed) 15 382,115
Post Falls Control Room T12s 15 1,776
Generating Floor HPS 15 3,312
Upper Falls
Utility Men Break Room Lighting 15 2,151
Control Room Lighting 15 4,340
Network Feeder Tunnel Lighting 15 8,344
Rathdrum CT Roadway Lighting 15 16,273 Halogen Pole Lights 15 3,200
Lighting Projects
The facilities have a mixture of T12, T8 and some T5 linear fluorescent fixtures as well as many incandescent bulbs. The proposed replacement fixtures from the lighting audits are primarily linear, high bay, and screw in LED fixtures. Noxon Rapids is the only facility with a completed a lighting retrofit. Shell Projects No shell measures are cost effective due to negligible savings and cost prohibitive nature of the measure due to the size of the facilities and large internal heat gain of the equipment in the facilities. However, small maintenance weatherization are available to improve occupant comfort.

8 Also saves 23,911 therms of natural gas per year.
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HVAC Projects
There are no recommendations to replace current HVAC equipment but there are recommendations to replace equipment with more efficient technology when each unit
reaches the end of its’ useful life. Controls on Process Motors There are a number of air compressors, fans and pumps driven by electric motors in
Avista’s facilities. These motors could use variable speed drives to match the current process needs and reduce the energy consumption of the motors as opposed to the current control systems. Table 5.6: Planned Generation Facility Efficiency Upgrades 2017 – 2018
Facility Description Measure Life (years)
Electric Savings (kWh)
Cabinet Gorge Lighting Retrofit 15 300,000
Little Falls Lighting Retrofit 15 62,266
Long Lake Lighting Retrofit 15 17,441 Nine Mile Lighting Retrofit 15 71,455
Demand Response
Over the past decade, demand response or DR gained attention as an alternative to new
generation to meet peak load growth. DR reduces load to specific customers during peak demand periods until the load event is over or the customer has met its commitment. Enrolling customers allows the utility to modify customer usage in exchange for bill discounts. National attention focuses on residential programs to control water heaters, space heating, and air conditioners. A 2013 IRP Action Item suggested further study of the DR potential based on its selection as a PRS resource from 2022 to 2027. Avista retained AEG to study the potential of future commercial and industrial programs for both the 2015 IRP and 2017 IRPs. Previous Demand Response Programs
Avista’s first DR experience began in the 2001 Energy Crisis. Avista responded with an 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 again led Avista to request DR through a media request for customers to conserve and short-term agreements with large industrial customers. During the 2006 event, Avista estimates DR reduced loads by
50 MW. Avista conducted a two-year residential load control pilot between 2007 and 2009 to study
specific technologies and examine cost-effectiveness and customer acceptance. The pilot tested scalable Direct Load Control (DLC) devices based on installation 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
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and customer-friendly manner. Avista installed DLC devices on 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. 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 feedback equipment. Information gained from the pilot is in the report filed with the Idaho Public Utilities Commission. 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. 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 control approach was non-traditional in several ways. First, the DR events
were not prescheduled, but Avista controlled customer loads defined by pre-defined 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. Lastly, value quantification extended beyond demand and energy savings and explored bill management options for customers with whole house usage data analyzed in conjunction with smart thermostat data. Inefficient homes identified through this analysis prompted customer engagement. For example, an operational anomaly prompted an investigation uncovering a control board
in a customer’s heat pump causing the system to draw warm air from inside the home during the heating season. This in turn caused the auxiliary heat to come on prematurely and cycle too frequently, resulting in high customer bills. The repair saved the customer
money and allowed them to be more comfortable in their home. Lessons learned from the SGDP program helped craft Avista’s new Smart Thermostat rebate program (an efficiency-only program) implemented in October 2014. The Smart Grid demonstration
project concluded December 31, 2014. Experiences from both residential DLC pilots (North Idaho Pilot and the SGDP) show participating customer engagement is high; however, recruiting participants is challenging. Avista’s service territory has high natural gas penetration for typical DLC space and water heat applications. Customers who have interest may not have qualifying equipment, making them ineligible for participation in the program. Secondly, customers
did not seem overly interested in the DLC program offerings. BPA has found similar challenges in gaining customer interest in their recent regional DLC programs. Finally, Avista is unable at this time to offer pricing strategies other than direct incentives to
compensate customers for participation in the program. Avista is committed to evaluating and considering DR to meet future load requirements if
it cost effective compared to other alternatives and does not influence the customer’s reliability or satisfaction with service. To fulfill this commitment, Avista will determine if a study is needed to evaluate the residential DR potential for the next IRP to meet its winter and summer peak requirements as part of this IRP’s action plan.
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Schedule 9, Page 80 of 205
Demand Response Comparison to the Seventh Power Plan
For DR, Avista reviewed the NPCC’s Seventh Plan and found some differences between
Avista’s DR analysis and the NPCC’s including 1) the NPCC’s analysis includes residential and agricultural programs, 2) specific summer and winter programs, and 3) the
NPCC excludes standby generator programs. Further, the NPCC models these programs in bins, rather than specific programs. Avista will determine if it is necessary to include residential DR programs in the 2019 IRP, but agricultural programs will be limited due to Avista’s limited irrigation pumping load, although other agricultural process were included in the industrial portion of the existing study. Avista only includes winter C&I programs in
its study, as at the time of the analysis Avista’s capacity requirements are winter peaking rather than summer peaking.
The NPCC estimates 600 MW9 of DR for the region; using Avista’s 3.5 percent share of the region10, equates to 21 MW of DR. Avista’s PRS, as described in Chapter 11, includes
9 MW of winter C&I DR and 35 MW of standby generation, for 44 MW11 of total peak load reduction. This more than doubles the amount of DR the NPCC includes as cost effective in the Seventh Power Plan.
Demand Response Potential Assessment Study Avista retained AEG to study the potential for commercial and industrial DR in Avista’s service territory for the 20-year planning horizon of 2018–2037. It primarily sought to develop reliable estimates of the magnitude, timing, and costs of DR resources likely available to Avista for meeting winter peak loads. The study focuses on resources assumed achievable during the planning horizon, recognizing known market dynamics
may hinder acquisition. Avista includes in the DR analysis savings from avoiding T&D losses, but does not include T&D capital deferral benefits as it is not determined whether or not a system peak DR program will actually defer any specific T&D investment.

The IRP incorporates DR study results, and the study will affect subsequent DR planning
and program development efforts. A full report outlining the DR potential for commercial and industrial customers is in Appendix C from the 2015 IRP. AEG updated the costs and savings for this IRP, but the report showing the amount of DR in Avista’s service territory is the same. Table 5.3 details achievable DR potential for the programs studied by AEG. Table 5.7: Commercial and Industrial Demand Response Achievable Potential (MW)
Program 2018 2019 2020 2037 2037
Direct Load Control 0.4 1.1 2.2 3.9 4.2
Firm Curtailment 5.8 11.6 17.5 17.7 18.2
Opt-in Critical Peak Pricing 0.1 0.4 0.9 4.4 4.6
9 NPCC’s Seventh Power Plan, page 3-4. 10 Avista’s estimate share of the region per the NPCC Sixth Power Plan, this calculation is not available for the Seventh Power Plan at this time.
11 The 44 MW figure does not include additional savings from transmission and distribution loses.
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Direct Load Control
A DLC program targeting Avista General and Large General Service customers in Washington and Idaho would directly control electric space heating load in winter, and water heating load throughout the year, through a load control switch or programmable
thermostat. Central electric furnaces, heat pumps, and water heaters would cycle on and off during high-load events. Typically, DLC programs take five years to ramp up to maximum participation levels.

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 return, they receive fixed incentive payments. Customers receive payments even if they never receive a load curtailment request. 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. Penalties are a possible component of a firm curtailment program.
Industry experience indicates customers with loads greater than 200 kW participate in firm curtailment programs. However, there are a few programs where customers with 100-kW maximum demand participate. In Avista’s case, the study lowered the demand threshold level to include Large General Service customers with an average demand of 100 kW or more. Customers with 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 obligations such as schools and hospitals, generally are not good candidates. Third parties generally administer firm curtailment programs for utilities and are responsible for all aspects of program implementation, including program marketing and outreach, customer recruitment, technology installation and incentive payments. Avista could contract with a third party to deliver a fixed amount of capacity reduction 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.

Critical Peak Pricing Critical peak pricing programs set prices much higher during short critical peak periods to encourage lower customer usage at those times. Critical peak pricing is usually offered in conjunction with time-of-use rates, implying at least three periods: critical peak, on-
peak and off-peak. Utilities offer heavy discounts to participating customers during off-peak periods, even relative to a standard time-of-use rate program. Event days generally are a day ahead or even during the event day. Over time, establishment of event-trigger
criteria enables customers to anticipate events based on hot weather or other factors.
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System contingencies and emergencies are candidates for Critical peak pricing. Critical
peak pricing differentials between on-peak and off-peak in the AEG study are 6:1, and available to all three commercial and industrial classes.
There are two ways to offer critical peak pricing. The opt-in rate allows voluntary enrollment in the program or the utility enrolls all customers in an opt-out program, requiring them to select another rate program if they do not want to participate. Avista is only modeling the opt-in program. The success of the critical peak pricing program will vary according to whether customers have enabling technology to automate their response. For General and Large General Service customers, the enabling technology is a programmable communicating thermostat. For Extra Large General Service customers,
the enabling technology is automated DR implemented through energy management and control systems.
Critical peak pricing programs require formal rate design based on customer billing data to specify peak and off-peak price levels and periods the rates are available. Rate design was outside the scope of the AEG study. Further, new metering technology is required.
Given these requirements, critical peak pricing was not an option for the IRP. Standby Generation Partnership Few utilities have contracted with large industrial customers to use their standby generation resources during peak load events or to provide non-spinning reserves. Avista studied a standby generation option similar to the Portland General Electric program where existing customers use their standby generation. Portland General Electric dispatches, tests, and maintains the customer generation resources in exchange for control of the resource in non-emergency situations. It uses customer generators for limited hours for peak requirements, operating reserves, and potentially for voltage
support on certain distribution feeders. Environmental regulations limit the use of backup generation facilities unless they meet strict emission guidelines. To provide more operating hours a program could introduce natural gas blending to improve the emissions and operating costs. Avista estimates approximately 40 MW12 of standby generation resources are available for utility use over 20-year acquisition period. The IRP assumes a standby generation program would cost $50 per kW in upfront investments, and $10 to $15 per kW-year in O&M costs. In May 2015, the federal courts overturned Reciprocating Internal Combustion Engine
(RICE) rule limiting the availability of standby generation resources. The RICE rule was remanded to EPA and remains in its 2013 form the former rule. Under clarification of this rule, the EPA allows generators to dispatch 50 hours per year in non-emergency
conditions. Local air authorities may further restrict qualifying generators to new technologies. In the event this program is part of Avista’s plans to meet resource deficits, additional environmental and potential studies will begin.
12 The AEG DR study included standby generation in its firm curtailment section, in the event both programs are cost effective, firm curtailment will include a 50 percent reduction in its capability.
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6. Long-Term Position
Introduction & Highlights
This chapter describes the analytical framework used to develop Avista’s net resource position. It describes reserve margins held to meet peak loads, risk-planning metrics used to meet hydroelectric variability, and plans to meet renewable goals set by Washington’s Energy Independence Act (EIA). Avista has unique attributes affecting its ability to meet peak load requirements. It connects to several neighboring utility systems, but is only 5 percent of the total regional load. Annual peaks can occur either in the winter or in the summer; but Avista is winter peaking on a planning basis using extreme weather conditions. The winter peak generally occurs in December or January, but may happen in November or February
when extreme weather events may occur. As described in Chapter 4 – Existing Supply Resources, Avista’s resource mix contains roughly equal amounts of hydroelectric and thermal generation. Hydroelectric resources meet most of Avista’s flexibility
requirements for load and intermittent generation, though thermal generation is playing a larger role as load growth and intermittent generation increase flexibility demands.
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 their dispatch and revenue. There is no industry standard reserve margin level; standardization across systems with varying resource mixes, system sizes, and transmission interconnections, is difficult.
NERC defines reserve margins as follows:
Section Highlights
Avista’s first long

Avista’s peak hour planning margin is 14

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Generally, the projected demand is based on a 50/50 forecast. Based on
experience, for Bulk Power Systems that are not energy-constrained, reserve
margin is the difference between available capacity and peak demand,
normalized by peak demand shown as a percentage to maintain reliable
operation while meeting unforeseen increases in demand (e.g. extreme weather)
and unexpected outages of existing capacity. Further, from a planning
perspective, planning reserve margin trends identify whether capacity additions
are keeping up with demand growth. As this is a capacity based metric, it does
not provide an accurate assessment of performance in energy limited systems,
e.g., hydro capacity with limited water resources. Data used here is the same
data that is submitted to NERC for seasonal and long-term reliability
assessments. Figures above shows forecast net capacity reserve margin in US
and Canada from 2008 to 2017.

NERC's Reference Reserve Margin is equivalent to the Target Reserve Margin
Level provided by the Regional/subregional’s own specific margin based on load,
generation, and transmission characteristics as well as regulatory requirements.
If not provided, NERC assigned 15 percent Reserve Margin for predominately
thermal systems and 10 percent for predominately hydro systems. As the
planning reserve margin is a capacity based metric, it does not provide an
accurate assessment of performance in energy limited systems, e.g., hydro
capacity with limited water resources.1
Avista and the region’s hydroelectric system is energy constrained, so the 10 or 15 percent metrics from NERC do not adequately define our planning margin. Beyond planning margins, as defined by NERC, a utility must maintain operating reserves to cover forced outages on the system. Avista includes operating reserves in addition to a planning margin. Per Western Electric Coordinating Council (WECC) requirements, Avista must maintain 1.5 percent of control area load and 1.5 percent of on-line control
area generation as spinning reserves.2 Then an additional 1.5 percent of control area load and 1.5 percent of on-line control area generation as non-spinning reserves. Avista must also maintain reserves to meet load following and regulation requirements of
within-hour load and generation variability, this amount equals 16 MW at the peak hour. Recently, the WECC began experimenting with changing the reserve rules. The current proposal is to keep three percent of load and three percent of generation as operating reserves, but to remove the requirement to hold half the reserves as spinning reserve. In lieu of spinning reserves is a requirement to hold 24 MW (for Avista) as Frequency Response Reserves (FRR). FRR can instantaneously respond to changes in frequency. Avista has sufficient FRR resource capability; but will require operational changes to
insure the units with this capability are available. Avista will not acquire additional capacity until its expected peak loads plus reserve margins exceed resources beyond 2026 either on a single-hour or on a sustained three-day basis.

1 http://www.nerc.com/pa/RAPA/ri/Pages/PlanningReserveMargin.aspx. 2 Spinning reserves synchronize to the system while stand-by reserves must be available within 10 minutes.
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Planning Margin
Utility capacity planning begins with identifying the broader regional capacity position, as regional surpluses can offset high planning margins and utility investments. The Northwest has a history of capacity surpluses and energy deficits because of its
hydroelectric generation base. Since the 2000-2001 energy crisis, the Northwest added nearly 6,400 MW of natural gas-fired generation. During this same time, Oregon and Washington added 7,890 MW of wind generation. Northwest load growth projections are
lower as compared to history, but with announced coal plant retirements and wind’s lack of on-peak capacity contribution, the region is approaching load-resource capacity balance, while retaining an energy surplus. Given the interconnected landscape of the Northwest power market, selecting a planning margin target is not straightforward. One approach is to conduct a regional loss of load probability (LOLP) study calculating the amount of capacity required to meet
a five percent LOLP threshold. Five percent LOLP means a utility meets all customer demand in all hours of the year in 19 of 20 years; this allows one loss-of-load event in a 20-year period. Regional LOLP analysis is beyond the scope of an IRP. Fortunately, the
NPCC conducts regional LOLP studies. The NPCC analyzes northwest resource adequacy. Based on their work, the northwest begins to fail the five percent LOLP measure in the winter of 2021-22 when major coal generators retire.3 The NPCC identifies a loss of load probability after conservation is 7.2 percent, assuming the region can import 2,500 MW of power from southern neighbors. The projected shortages occur primarily in the winter, but now the summer
as well, the same periods when Avista would expect its peak loads to occur. The summer LOLP is new to the Council’s analysis prompting Avista to consider a summer planning margin. In prior studies during the 2015 IRP cycle, the Council concluded the
region had enough capacity to meet summer demand. The recent change is due to additional coal plant retirement announcements.
Avista is an interconnected utility, an advantage over its sister utility Alaska Electric Light & Power (AELP). AELP is an electrical island and must meet all loads instantaneously using its own resources without relying on its neighbors. AELP retains large reserve margins to account for avalanche danger – typically 115 percent of peak load. Avista, as an interconnected utility, can rely on its neighbors (and the neighbors can rely on Avista) to lower planning margins. The harder question is how much reliance it should place on the wholesale market. Wholesale markets are important to
help meet load when controlled resource dispatch is not available from factors such as economic dispatch, forced or planned outages, low renewable energy production (such as wind/hydro), or higher than normal loads. In the 2013 IRP, Avista found a 30 percent
planning margin (in addition to operating reserves) would be required to meet the 5 percent LOLP without connecting to the wholesale market. This higher planning margin is due to Avista’s large resources as compared to its load. Since Avista is an interconnected utility, a lower planning margin of 14 percent (winter) and seven percent (summer) is included in the plan to balance the reliance on the marketplace when large
3https://www.nwcouncil.org/media/7491213/2017-5.pdf.
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resources have forced outages or other combination of events. This difference results in
Avista requiring 270 MW less winter peak generation in 2018 than if Avista was an electrical island, a similar amount to its largest contingencies. The total requirement for planning margin and other reserves equates to a 22.6 percent planning margin.
Avista studied planning margins used by transmission organizations and utilities across the country as part of the 2015 IRP. The results varied depending on the amount and
size of their interconnections and the resource mix within their systems. One challenge in comparing planning margins across utilities is determining if they include ancillary service, or operating reserve, obligations in their planning margins. Utilities with minimal interconnections or a large hydroelectric system have higher planning margins than better-interconnected and/or thermal-based systems. Avista and its neighbors generally meet a large portion of their load obligations with hydroelectric resources, implying that their planning margins might need to be higher than NERC’s 15 percent
recommendation. Another consideration when selecting the appropriate planning margin is the utility’s
largest single contingency relative to peak load. Avista’s largest single unit contingency is Coyote Springs 2. This plant is 18.8 percent of weather-adjusted peak load in 2018, a high statistic relative to Western Interconnect peers. Some resource planners argue planning margins should be no smaller than a utility’s single largest contingency on the basis that if the largest resource fails, other resources may not be able to replace it. Given the Northwest’s contingency reserve sharing agreement, lower reserve levels are required for the first hour following a qualifying generation outage. Signatories to the contingency reserve sharing agreement can call on assistance from neighboring utilities for up to 60 minutes to help meet shortages. Beyond the first hour, utilities are responsible for replacing the lost power themselves, either from other utility resources,
from purchases from other generators, or from load reductions.
In Avista’s prior LOLP studies, both summer and winter capacity shortages are possible due to high peak loads. Past IRPs planned to utilize the wholesale market for summer capacity due to the amount of available surplus market capacity. As this capacity surplus shrinks, Avista is changing its summer planning margin to seven percent plus operating reserves and regulation. Avista chose the seven percent planning margin by comparing the standard deviation of potential loads in the summer (69 MW) to winter peak load standard deviation (138 MW).4 Avista concluded the summer planning margin should be half of the winter planning margin because the standard deviation of summer
potential peak loads is half of the winter peak loads. Avista will continue to analyze planning margins using its loss of load model to validate or update this requirement as part of the 2019 IRP. Avista will monitor the summer market depth and may revise the
planning margin standard from after reviewing work by the NPCC. The addition of a seven percent summer planning margin for this IRP does not add additional resources requirements above the winter peak requirement due to our dual peaking load profile, but it will require the selection of resources than can provide both winter and summer
4 Peak winter loads can occur from the last two weeks of November through the second week of February. The standard deviation of all the monthly peak loads in this period is 138 MW.
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peaking capabilities. Avista intends on meeting this requirement using owned resources
or power purchase agreements (PPAs) as identified in Chapter 11 – Preferred Resource Strategy. Avista does not plan to use short-term market purchases to meet the 14 and seven percent planning margin requirements.
Northwest Power and Conservation Council Operating Reserve Planning Data The NPCC’s Seventh Plan and the Washington Commission’s 2015 IRP acknowledgment letters request utilities to provide additional documentation regarding reserves:
Utilities should include their planning assumptions for the provision of operating
reserves in their Integrated Resource Plans and Bonneville in its Resource Program.
These assumptions should emphasize reliability ahead of economic operations, that
is, reasonable estimates for times of power system stress. The following should also
be included:

 An estimate of the utility’s or Bonneville’s requirement for operating reserves
 Reasonable planning assumptions for the amount of the reserve requirement
estimated to be held on hydropower generation and which projects should be
assigned in power system models to provide these reserves
 Reasonable planning assumptions for the amount of the reserve requirement
estimated to be held on thermal plants and which plants should be assigned
in power system models to provide these reserves
 Reasonable planning assumptions for any third-party provision of reserves5
In response to this request, Avista provides the following:
 Avista includes operating reserves as part of its planning criteria; these operating reserves are not included in the 14 percent winter or the seven percent summer planning margin calculations. For the 2018 winter peak hour estimated load, the operating reserves sum to 122 MW.6 An additional 16 MW7 of capacity is for within hour requirements such as regulation.
Regulation is typically met with Avista’s hydroelectric facilities. Avista tends to
hold out of the money thermal resources as non-spinning reserve resources and the remaining requirements at its hydroelectric facilities. The amounts held at the hydroelectric system versus thermal facilities depends on water
conditions and plant economics. For example, it is possible to hold all these reserves on the hydroelectric system in summer months due to lower flows
and Avista’s storage at both the Noxon Rapids and Mid-Columbia projects.
 Avista has several hydroelectric units with the ability to provide operating
reserves; these include Noxon Rapids, Cabinet Gorge, Long Lake and contracted Mid-Columbia projects. These facilities provide both spinning and
5 Northwest Power and Conservation Council’s Seventh Power Plan, Chapter 4, Page 7, REG-4 6 Avista holds operating reserves for the entire control area, including non-Avista generation and loads. 7 Avista typically holds 20 MW for both increases and decreases during normal operating conditions (non-peak event), but may vary depending on wind forecasts.
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non-spinning reserves. Under the new FRR rules, only four units at Noxon
Rapids and one of Cabinet Gorge’s units can provide this capacity.
 Avista can also provide operating reserves with its thermal fleet. Rathdrum CT, and Northeast CT can provide non-spinning reserves. Coyote Springs 2 and Lancaster can provide non-spin, spinning, and FRR reserves when the
units are not at full capacity.
 Avista on occasion will contract to sell reserves to other control areas under short-term agreements, but this information is proprietary. Energy Imbalance Market
Avista recently participated in a regional effort to evaluate the viability of an intra-hour Energy Imbalance Market (EIM) in the Northwest Power Pool area. The Market
Coordination (MC) Initiative officially launched on March 19, 2012 to explore alternatives to address the growing operational and commercial challenges to integrate variable energy resources affecting the regional power system. In December 2015, the MC
evaluation effort concluded. The agreement ended after the group could not agree to a final market design and several participants decided to join the California Independent System Operator (CAISO) Western EIM. Avista is conducting a cost/benefit analysis associated with joining the CAISO EIM. This analysis will be complete in the fall of 2017. Avista is also evaluating other factors influencing the decision to join the CAISO EIM. These include the reduction of near term
market liquidity as other utilities join the EIM and the additional integration of renewable resources in our service territory. Avista will use the cost/benefit analysis and evaluation of other market factors to inform its decision to participate in the Western EIM.
Balancing Loads and Resources
Both single-hour and sustained-peaking requirements compare future load and
resource projections to identify any shortages. The single peak hour is a larger concern in the winter than the three-day sustained 18-hour peak. During winter months, the hydroelectric system can sustain generation levels for longer periods than in the summer due to higher inflows. Figure 6.1 illustrates the winter balance of loads and resources. The first year Avista has a significant winter capacity deficit is November 2026 when including future conservation acquisitions. If all conservation programs ended, the first capacity deficit would occur in January 2022. Until recently, the capacity
position was short beginning in 2022, but the extension of a PPA from the Mid-Columbia PUDs filled this deficiency. Avista plans to meet its summer peak load with a smaller planning margin than in the winter. During summer months, operating reserve and regulation obligations are included in addition to a seven percent planning margin. Market purchases in the deep regional market should satisfy any weather-induced load variation or generation forced outage that otherwise would be included in the planning margin as is the case in the higher 14 percent winter planning margin. Resource additions to serve winter peaks meet smaller summer deficits as well. Figure 6.2 shows Avista’s summer resource
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balance. Like the winter, Avista expects its first summer deficit in 2027 after the
expiration of the Lancaster PPA in October 2026. Figure 6.1: Winter One-Hour Capacity Load and Resources
Figure 6.2: Summer One-Hour Capacity Load and Resources

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Energy Planning
For energy planning, resources must be adequate to meet customer requirements even when loads are high for extended periods, or a sustained outage limits the contribution of a resource. Where generation capability is not adequate 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 accounting for variations in month-to-month hydroelectric generation.
As with capacity planning, there are differences in regional opinions on the proper method for establishing energy-planning margins. Many utilities in the Northwest base their energy planning margins on the amount of energy available during the “critical water” period of 1936/37.8 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. The IRP could target resource development to reach a 99 percent confidence level on being able to deliver
energy to its customers, and it would significantly decrease the frequency of its 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
of the 2017 IRP to cover a one-in-one-hundred year event. Investments to support this high level of reliability would increase pressure on retail rates for a modest benefit. Avista plans to the 90th percentile for hydroelectric generation. Using this metric, there is a one-in-ten-year chance of needing to purchase energy from the market in any given month over the IRP timeframe. Beyond load and hydroelectric variability, Avista’s legacy WNP-3 contract with BPA
contains supply risk. The contract includes a return energy provision in favor of BPA that can equal 32 aMW annually. Under adverse market conditions, BPA almost certainly would exercise this right, as it did during the 2001 Energy Crisis. To account
for this contract risk, the energy contingency increases by 32 aMW until the contract expires in 2019. With the addition of WNP-3 contract contingency to load and hydroelectric variability, the total energy contingency amount equals 231 aMW in 2018.
See Figure 6.3 for the summary of the annual average energy load and resource net position.
8 The critical water year represents the lowest historical generation level in the streamflow record.
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Figure 6.3: Annual Average Energy Load and Resources
Washington State Renewable Portfolio Standard
Washington’s EIA requires utilities with more than 25,000 customers to source 9 percent of their energy from qualified renewables through 2019 and 15 percent by 2020. Utilities also must acquire all cost effective conservation as explained in Chapter 5 –
Energy Efficiency and Demand Response. 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 50-MW Kettle Falls project to qualify for the EIA goals beginning in 2016. Table 6.1 shows the forecast amount of RECs Avista needs to meet the EIA renewable requirement and the amount of qualifying resources already in Avista’s generation portfolio. Without the ability to roll RECs from previous years, Avista would require
additional renewables in 2026. With this ability, Avista does not need additional EIA resources over the planning horizon of this IRP. The company may have surplus RECs depending upon the qualifying output of Kettle Falls and Palouse Wind. Kettle Falls
qualifying output varies depending upon the availability of qualifying fuel and the economics of the facility. Given its expected renewables surplus until 2020, Avista will market the excess RECs until 2019. Beginning in 2019, surplus RECs will roll into 2020, allowing the banking provision to delay additional renewable resource investment.
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Table 6.1: Washington State EIA Compliance Position Prior to REC Banking (aMW)
2018 2020 2025 2030 2035 Percent of Washington Sales 9% 15% 15% 15% 15%
Two-Year Rolling Average Washington Retail
Sales Estimate 644 658 683 699 720

Renewable Goal -58 -99 -103 -105 -108 Incremental Hydroelectric 22 22 22 22 22
Net Renewable Goal -36 -77 -81 -83 -86

Other Available REC's
Palouse Wind with Apprentice Credits 48 48 48 48 48
Kettle Falls 33 33 33 33 33
Net Renewable Position (before rollover RECs) 45 4 0 -2 -5

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7. Policy Considerations
Public policy affects Avista’s current generation resources and the resources it can pursue. Each resource option presents different cost, environmental, operational, political, regulatory, and siting challenges. Regulatory environments regarding energy topics such as renewable energy 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 development and continued use of coal and natural gas-fired generation. This chapter discusses pertinent public policy issues relevant to the IRP.

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, renewable portfolio standards, financial risk
management, and meeting changing environmental requirements. Each generating resource has distinctive operating characteristics, cost structures, and environmental regulatory challenges that can change significantly based on timing and location. 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. Traditional thermal generation technologies, like coal and natural gas-fired plants, provide reliable capacity and energy. New coal plants as compared to natural gas-fired resources have environmental and economic disadvantages. It is unlikely without major technological improvements any new coal-fired resources will be developed in the U.S. Existing coal-fired resources are also under increasing pressure from lower-cost resources and increasing regulatory constraints and costs.
Natural gas-fired plants have relatively low capital costs, can typically be located closer to load centers, have relatively short construction time frames, lower emissions and fewer waste issues than coal, and are often the only available utility-scale baseload resource. On the other hand, higher fuel price volatility historically affected natural gas-fired plant economics. In addition, their performance decreases in hot weather, they are difficult to site with sufficient water rights for their efficient operation, and they emit greenhouse
gases.
Chapter Highlights

Avista’s Climate Policy Council monitors greenhouse gas legislation and

does not directly impact any of Avista’s generating fleet.
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Renewable energy technologies such as wind, biomass, geothermal, and solar have
different benefits and challenges. Renewable resources have low or no fuel costs and few, if any, direct emissions. However, solar and wind-based generation have limited or no capacity value, their own unique siting limitations, and their variable output can present
integration challenges requiring additional capacity investments. Renewable resources are often located to maximize capability rather than proximity to load centers. The need to site renewable resources in remote locations often requires significant investments in
transmission and capacity expansion, as well as mitigating possible wildlife and aesthetic issues. Distributed resources may alleviate some of these issues, but the price differentials of distributed resources make them more difficult to develop at utility scale. Unlike fossil fuel-fired plants, the fuel for non-biomass renewables may not be transportable to utilize existing transmission or to minimize opposition to project development. Dependence on the health of the forest products industry and access to biomass materials, often located in publicly owned forests, poses challenges to biomass
facilities. Transportation costs and logistics also complicate the location of biomass plants.
The long-term economics of renewable resources also faces some uncertainties. Federal investment and production tax credits are set to expire. The extension credits and grants may not be sustainable given their impact on government finances and the maturity of wind and solar technologies. Many relatively unpredictable factors affect renewables, such as renewable portfolio standards (RPS), construction and component prices, international trade issues and currency exchange rates. Decreasing capital costs for wind and solar may slow or stop. The design and scope of greenhouse gas regulation is in a state of flux due to legal challenges and evolving political realities. As a result, greenhouse gas policy-making is
shifting from the federal to the state and local level. Since the 2015 IRP publication, changes in the approach to greenhouse gas emissions regulation and supporting programs, include:

 The EPA proposed actions to regulate greenhouse gas emissions under the Clean Air Act (CAA) through the proposed Clean Power Plan (CPP) were stayed by the U.S. Supreme Court on February 9, 2016;
 The President signaled a shift in federal priorities through Executive Orders as well as proposed budgets.
 EPA plans to reevaluate the CPP and submit a new CPP proposal to the Office of Management and Budget;
 California failed to pass an extension to its cap-and-trade program beyond 2020, but did raise its RPS to 50 percent and expanded energy storage requirements; and
 The State of Washington implemented the Clean Air Rule

Natural Gas System Emissions The physical makeup of the natural gas system includes extraction rigs, pipelines and
storage; each of these facilities have fugitive emissions. Fugitive emissions are the
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unintended or irregular releases of natural gas as part of the production cycle. The EPA
introduced the Natural Gas STAR Program in 1993 in response to these emissions concerns. This Natural Gas STAR Program is a voluntary program allowing the self-reporting of emission reduction technologies and practices and includes all of the major
industry sectors. In May 2016, the EPA finalized rules to reduce methane emissions from wells under the CAA. The program requires natural gas well owners to find and repair leaks at the well site no less than twice per year and four times per year at compressor stations. The EPA placed a 90-day delay on portions of the rule to allow additional comments. Natural gas wells utilizing shale deposits have a high production curve at the beginning
of the extraction process and then dramatically levels off. If not constructed properly, there is a risk of leakage that may lower the return on investment. In addition, risk of increased regulation incentivizes producers to manage emissions as effectively as possible as more
regulations generally increase costs and reduce return on investments. Over time a smaller return on investment could mean the difference in survival outcomes for each producer.
Avista’s Climate Change Policy Efforts
Avista’s Climate Policy Council is an interdisciplinary team of management and other
employees that:
 Facilitates internal and external communications regarding climate change issues;
 Analyzes policy impacts, anticipates opportunities, and evaluates strategies for Avista Corporation; and
 Develops recommendations on climate related policy positions and action plans. The core team of the Climate Policy Council includes members from Environmental Affairs, Government Relations, External Communications, Engineering, Energy Solutions, and Resource Planning groups. Other areas participate for topics as needed. The meetings for this group include work for both immediate and long-term concerns.
Immediate concerns include reviewing and analyzing proposed or pending state and federal legislation and regulation, reviewing corporate climate change policy, and responding to internal and external requests about climate change issues. Longer-term
issues involve emissions measurement and reporting, different greenhouse gas policies, actively participating in legislation, and benchmarking climate change policies and activities against other organizations. Membership in the Edison Electric Institute is Avista’s main vehicle to engage in federal-level climate change dialog, supplemented by other industry affiliations. Avista monitors regulations affecting hydroelectric and biomass generation through its membership in
other associations. State and Federal Environmental Policy Considerations The CPP was the focus of federal greenhouse gas emissions policies in the 2015 IRP and the starting point for this IRP emission reduction assumptions. Details about greenhouse gas emissions modeling are in Chapter 10 – Market Analysis. As explained
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above, the application and form of the future CPP is uncertain as this IRP is being written.
However, a form of federal regulation will be put in place. As explained in Chapter 10, this IRP does not include specific carbon pricing with the exception of states and provinces with existing carbon trading and taxing regulations. This IRP does include regional
emission reduction goals leading to a shadow price of carbon pricing, rather than an arbitrary carbon price. If a carbon tax or cap and trade program develops in the future, it will require alternative analysis in a later IRP. EPA Regulations EPA regulations, or the States’ authorized versions, directly, or indirectly, affecting electricity generation include the CAA, along with its various components, including the
Acid Rain Program, the National Ambient Air Quality Standard, the Hazardous Air Pollutant rules, and Regional Haze Programs. The U.S. Supreme Court ruled the EPA has authority under the CAA to regulate greenhouse gas emissions from new motor
vehicles and the EPA has issued such regulations. When these regulations became effective, carbon dioxide and other greenhouse gases became regulated pollutants under the Prevention of Significant Deterioration (PSD) preconstruction permit program and the
Title V operating permit program. Both of these programs apply to power plants and other commercial and industrial facilities. In 2010, the EPA issued a final rule, known as the Tailoring Rule, governing the application of these programs to stationary sources, such as power plants. EPA proposed a rule in early 2012, and modified in 2013, setting standards of performance for greenhouse gas emissions from new and modified fossil fuel-fired electric generating units and for existing sources through the draft CPP in June 2014. The EPA released the final CPP rules and the Carbon Pollution Standards (CPS) as published in the Federal Register on October 23, 2015, when they were both challenged thorough a series of lawsuits. Standards under Section 111(d) of the CAA are currently stayed by the Supreme Court. The EPA also finalized new source performance
standards (NSPS) for new, modified and reconstructed fossil fuel-fired generation under CAA section 111(b).
Promulgated PSD permit rules may affect Avista’s thermal generation facilities in the future. These rules can affect the amount of time to obtain permits for new generation, major modifications to existing generating units, and the final limitations contained in permits. The promulgated and proposed greenhouse gas rulemakings mentioned above have been legally challenged in multiple venues so we cannot fully anticipate the outcome or extent our facilities may be impacted, nor the timing of rule finalization. Clean Air Act Operating Permits The CAA, originally adopted in 1970 and modified significantly since, intends to control covered air pollutants to protect and improve air quality. Avista complies with the
requirements under the CAA in operating our thermal generating plants. Title V operating permits are required for our largest generation facilities and are renewed every five years. Title V operating permit renewal applications are in process for Colstrip Units 3 and 4, Coyote Springs 2 and Kettle Falls. Boulder Park, Northeast CT, and other small facilities require only minor source operating or registration permits based on their limited operation and emissions. Discussion of some major CAA programs follows.
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New Source Proposal
After receiving over 2.5 million comments on the April 2012 proposal for new resources under section 111(b) of the CAA, the EPA withdrew that proposal and submitted a new proposal on September 20, 2013. This proposal covers new fossil fuel-fired resources
larger than 25 MW for the following resource types:
 Natural gas-fired stationary combustion turbines: 1,000 pounds CO2 per MWh for units burning greater than 850 mmBtu/hour and 1,100 pounds CO2 per MWh units
burning less than or equal to 850 mmBtu/hour.
 Fossil fuel-fired utility boilers and integrated gasification combined cycle (IGCC) units: 1,100 pounds CO2 per MWh over a 12-operating month period or 1,000–1,500 pounds CO2 per MWh over a seven-year period. The EPA finalized the new source standard on August 3, 2015. The final rule differs from the proposal, which was the basis for the development of this IRP. The final rule guided modeling assumptions for the 2017 IRP. Acid Rain Program The Acid Rain Program is an emission-trading program for reducing nitrous dioxide by
two million tons and sulfur dioxide by 10 million tons below 1980 levels from electric generation facilities. Avista manages annual emissions under this program for its ownership interest in Colstrip Units 3 and 4, Coyote Springs 2, and Rathdrum. National Ambient Air Quality Standards EPA sets National Ambient Air Quality Standards for pollutants considered harmful to public health and the environment. The CAA requires regular court-mandated updates to occur for nitrogen dioxide, ozone, and particulate matter. Avista does not anticipate any material impacts on its generation facilities from the revised standards at this time. Hazardous Air Pollutants (HAPs) HAPs, often known as toxic air pollutants or air toxics, are pollutants that may cause cancer or other serious health effects. EPA regulates toxic air pollutants from a published
list of industrial sources referred to as "source categories". These pollutants must meet control technology requirements if they emit one or more of the pollutants in significant quantities. EPA finalized the Mercury Air Toxic Standards (MATS) for the coal and oil-fired source category in 2012. Colstrip Units 3 & 4’s existing emission control systems should be sufficient to meet mercury limits. For the remaining portion of the rule that utilized Particulate Matter as a surrogate for air toxics (including metals and acid gases), the Colstrip owners reviewed recent stack testing data and expected that no additional
emission control systems would be needed for Units 3 & 4 MATS compliance. Regional Haze Program
EPA set a national goal to eliminate man-made visibility degradation in Class I areas by the year 2064. Individual states are to 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,
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EPA may adopt Federal Implementation Plans (FIPs). On September 18, 2012, EPA
finalized the Regional Haze FIP for Montana. The FIP includes both emission limitations and pollution controls for Colstrip Units 1 and 2. Colstrip Units 3 and 4 are not currently affected, although the units will be evaluated for Reasonable Progress at the next review
period in September 2017. Avista does not anticipate any material impacts on Colstrip Units 3 and 4 at this time. 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. EPA Mandatory Reporting Rule Any facility emitting over 25,000 metric tons of greenhouse gases per year must report
its emissions to EPA. Colstrip Units 3 and 4, Coyote Springs 2, and Rathdrum currently report under this requirement. The Mandatory Reporting Rule also requires greenhouse gas reporting for natural gas distribution system throughput, fugitive emissions from
electric power transmission and distribution systems, fugitive emissions from natural gas distribution systems, and from natural gas storage facilities. Washington requires mandatory greenhouse gas emissions reporting similar to the EPA requirements and
Oregon has similar reporting requirements. Coal Ash Management and Disposal The EPA issued a final rule regarding coal combustion residuals (CCR) in 2014. This affects Colstrip since it produces CCR. The rule establishes 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 CCR rule became effective October 2015. The owners of Colstrip are developing a multi-year plan to comply with the new CCR standards. Any financial or operational impacts to Colstrip from the CCR are still estimates, but are included in this IRP.
Particulate Matter Particulate Matter (PM or particle pollution) is the term 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 be seen with the naked eye. Others are so small they can only be detected using 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 that are 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 EPA to periodically review the standards to ensure that they provide adequate health and environmental protection, and to update those standards as necessary.
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Avista has ownership and/or operational control for the following thermal electric
generating stations: Boulder Park, Colstrip, Coyote Springs, Kettle Falls, Lancaster, Northeast and Rathdrum that produce PM. Table 7.1 shows each of these generating stations, location, status of the surrounding area with NAAQS for PM2.5 and PM10, operating permit and PM pollution controls. Table 7.1: Avista Owned and Controlled PM Emissions
Thermal Generating Station
Location County, City, State
PM2.5 NAAQS Status
PM10 NAAQS Status
Air Operating Permit
PM Pollution Controls
Boulder Park Spokane Co., Spokane, WA Attainment Maintenance Minor Source Pipeline Natural Gas
Colstrip Rosebud Co., Lame Deer, MT Attainment Non-Attainment Major Source
Title V OP
Fluidized Bed Wet Scrubber
Coyote Springs Morrow Co., Boardman, OR Attainment Attainment Major SourceTitle V OP
Pipeline Natural Gas, Air filters
Kettle Falls Lincoln Co., Kettle Falls, WA Attainment Attainment Major Source
Title V OP
Multi-clone collector,
Electrostatic Precipitator
Lancaster Kootenai Co., Rathdrum, ID Attainment Attainment Major SourceTitle V OP
Pipeline Natural Gas, Air filters
Northeast Spokane Co., Spokane, WA Attainment Maintenance Minor Source Pipeline Natural Gas, Air filters
Rathdrum Kootenai Co., Rathdrum, ID Attainment Attainment Major SourceTitle V OP
Pipeline Natural Gas, Air filters

Our generating stations are issued air quality operating permits from the appropriate EPA delegated air quality agency under the authority of the Federal CAA. These operating permits require annual compliance certifications and are fully renewed every five years to incorporate any new standards including any updated NAAQS status. If warranted, EPA would issue specific requirements to protect human health and the environment at that time. 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 carbon tax, and emissions performance standards for power plants. Comprehensive climate change policy can include multiple components, such as
renewable portfolio standards, energy efficiency standards, and emission performance standards. Washington enacted all of these components, but other Avista jurisdictions have not. Individual state actions produce a patchwork of competing rules and regulations for utilities to follow and may be particularly problematic for multi-jurisdictional utilities
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such as Avista. There are 29 states, plus the District of Columbia, with active renewable
portfolio standards, and eight additional states have adopted voluntary standards.1 Idaho Policy Considerations
Idaho does not regulate greenhouse gases or have an RPS. There is no indication Idaho is moving toward regulation of greenhouse gas emissions beyond federal regulations. Montana Policy Considerations
Montana’s RPS law requires covered utilities to meet 15 percent of their load with qualified renewables since 2015. Montana implemented a mercury emission standard under Rule 17.8.771 in 2009. The standard exceeds the most recently adopted federal mercury limit.
Avista’s generation at Colstrip Units 3 and 4 have emissions controls currently meeting
Montana’s mercury emissions goal. Oregon Policy Considerations The State of Oregon has a history of greenhouse gas emissions and renewable portfolio standards legislation. The Legislature enacted House Bill 3543 in 2007, calling for, but
not requiring, reductions of greenhouse gas emissions to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050. Compliance is expected through a combination of the RPS and other complementary policies, like low carbon fuel standards and energy efficiency measures. The state has been working towards the adaptation of comprehensive requirements to meet these goals. Oregon’s SB 1547, enacted in March 2016, ends the use of coal to serve Oregon loads by 2030 and increases the RPS to 50 percent by 2040. HB 2135, or the cap and trade bill, is under consideration at the time this chapter is being written. This bill would repeal the greenhouse gas emissions goals stated above and would require the Environmental Quality Commission to adopt greenhouse gas emissions goals for 2025, and set limits for years 2035 and 2050.
These reduction goals are in addition to a 1997 regulation requiring fossil-fueled generation developers to offset carbon dioxide (CO2) emissions exceeding 83 percent of
the emissions of a state-of-the-art gas-fired combined cycle combustion turbine by funding offsets through the Climate Trust of Oregon. Washington State Policy Considerations The State of Washington has enacted several fossil-fueled generation emissions and resource diversification measures. A 2004 law requires new fossil-fueled thermal electric generating facilities of more than 25 MW of generation capacity to offset CO2 emissions
through third-party mitigation, purchased carbon credits, or cogeneration. An agreement with the State of Washington requires the Centralia Coal Plant to shut down one unit by December 2020 and the other unit by December 2025.

Washington’s EIA requires utilities with more than 25,000 retail customers to use qualified renewable energy or renewable energy credits to serve nine percent of retail load by 2012 and 15 percent by 2020. Failure to meet RPS requirements results in at least a $50 per MWh fine. The initiative also requires utilities to acquire all cost-effective conservation
1 http://www.dsireusa.org/resources/detailed-summary-maps/
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and energy efficiency measures up to 110 percent of avoided cost. Additional details
about the energy efficiency portion of the EIA are in Chapter 6 – Long-Term Position. In 2012, Senate Bill 5575 amended the EIA to define Kettle Falls Generating Station and
other legacy biomass facilities commencing operation before March 31, 1999 as EIA-qualified resources beginning in 2016. A 2013 EIA amendment allows multistate utilities to import RECs from outside the Pacific Northwest to meet renewable goals and allows
utilities to acquire output from the Centralia Coal Plant without jeopardizing alternative compliance methods. Avista will meet or exceed its renewable requirements in this IRP planning period through a combination of qualified hydroelectric upgrades, wind generation from the Palouse Wind PPA, and output from its Kettle Falls generation facility. The 2017 IRP Expected Case ensures that Avista meets all EIA RPS goals.
Former Governor Christine Gregoire signed Executive Order 07-02 in February 2007 establishing the following GHG emissions goals:
 1990 levels by 2020;
 25 percent below 1990 levels by 2035;
 50 percent below 1990 levels by 2050 or 70 percent below Washington’s expected
emissions in 2050;
 Increase clean energy jobs to 25,000 by 2020; and
 Reduce statewide fuel imports by 20 percent. The Washington Department of Ecology adopted regulations to ensure that its State Implementation Plan comports with the requirements of the EPA's regulation of
greenhouse gas emissions. We will continue to monitor actions by the Department as it may proceed to adopt additional regulations under its CAA authorities. In 2007, Senate Bill 6001 prohibited electric utilities from entering into long-term financial commitments beyond five years for fossil-fueled generation creating 1,100 pounds per MWh or more of greenhouse gases. Beginning in 2013, the emissions performance standard is lowered every five years to reflect the emissions profile of the latest commercially available CCCT. The emissions performance standard effectively prevents utilities from developing new coal-fired generation and expanding the generation capacity of existing coal-fired generation unless they can sequester emissions from the facility. The Legislature amended Senate Bill 6001 in 2009 to prohibit contractual long-term financial
commitments for electricity deliveries that include more than 12 percent of the total power from unspecified sources. The Department of Commerce filed a rule adopting a standard of 970 pounds per MWh for greenhouse gas emissions on March 6, 2013, with rules
becoming effective on April 6, 2013.2 Commerce announced that work for the next update would begin in the summer of 2017.
2 http://www.commerce.wa.gov/Programs/Energy/Office/Utilities/Pages/EmissionPerfStandards.aspx
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April 29, 2014, Washington Governor Jay Inslee issued Executive Order 14-04,
“Washington Carbon Pollution Reduction and Clean Energy Action.” The order created a
“Climate Emissions Reduction Task Force” tasked with providing recommendations to the Governor on designing and implementing a market-based carbon pollution program to
inform possible legislative proposals in 2015. The order also called on the program to
“establish a cap on carbon pollution emissions, with binding requirements to meet our
statutory emission limits.” The order also states that the Governor’s Legislative Affairs
and Policy Office “will seek negotiated agreements with key utilities and others to reduce
and eliminate over time the use of electrical power produced from coal.” The Task Force issued a report summarizing its efforts, which included a range of potential carbon-
reducing proposals. Subsequently, in January 2015, at Governor Inslee’s request, the
Carbon Pollution Accountability Act was introduced as a bill in the Washington legislature. The bill includes a proposed cap and trade system for carbon emissions from a wide range of sources, including fossil-fired electrical generation, “imported” power generated
by fossil fuels, natural gas sales and use, and certain uses of biomass for electrical generation. The bill was not enacted during the 2015 legislative session. After the conclusion of the 2015 legislative sessions, Governor Inslee directed the Department of
Ecology to commence a rulemaking process to impose a greenhouse gas emission
limitation and reduction mechanism under the agency’s CAA authority to meet the future emissions limits established by the Legislature in 2008. This resulted in Washington’s Clean Air Rule (CAR). The CAR imposes new compliance obligations on sources identified by Ecology. The rule imposes caps and requirements to reduce or offset emissions on large emitting facilities, fuel providers and natural gas distribution companies. It initially applies to 29 entities. Compliance obligations for energy-intensive trade-exposed industries, including pulp and paper manufacturers, steel and aluminum manufacturers and food processors, are
deferred for three years. When fully implemented, the CAR could cover as many as 70 emitters who account for about two-thirds of Washington’s emissions. The CAR caps emissions for facilities emitting more than 100,000 metric tons per year, and reduces the
emissions threshold by 5,000 metric tons per year, until covering all entities emitting over 70,000 metric tons by 2035. The Washington Commission may implement rules regarding RCW 70.235, from the Executive Order 07-02. The CAR became effective January 1, 2017 and is currently under legal challenge. Avista does not have any generating facilities under the CAR rule.
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8. Transmission & Distribution Planning

Introduction
This chapter introduces the Avista Transmission and Distribution systems and provides a brief description of how Avista studies these systems and recommends projects that keep the systems functioning reliably. Avista’s Transmission System is only one part of the
networked Western Interconnection, so a discussion of regulations and regional planning is also provided. This chapter includes a brief summary of planned transmission projects and generation interconnection requests currently under study, and provides links to documents describing these studies in more detail. Further, this section describes how distribution planning is now playing a role in the IRP.
Avista Transmission System
Avista owns and operates a system of over 2,200 miles of electric transmission facilities including approximately 660 miles of 230 kV transmission lines and 1,550 miles of 115 kV transmission lines (see Figure 8.1). Figure 8.1: Avista Transmission System

Section Highlights
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230 kV Backbone
The backbone of the Avista Transmission System functions 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 System Areas
Avista separates its Transmission System into five geographical study areas: 1. Big Bend
2. Coeur d’Alene 3. Lewiston-Clarkston 4. Palouse 5. Spokane Figure 8.3 shows the approximate boundaries of the study areas and these areas are
referenced individually in Avista’s Local Planning Report.

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Figure 8.3: Avista Transmission System Planning Regions
Transmission Planning Requirements and Processes
Avista coordinates its transmission planning activities with neighboring interconnected transmission operators. 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 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 operating and planning among its membership. WECC is the largest geographic territory of the regional entities with delegated authority from the NERC and
the FERC. It covers all or parts of 14 Western states, the provinces of Alberta and British Columbia, and the northern section of Baja, Mexico.1 See Figure 8.4 for the map of WECC. Peak Reliability Peak Reliability (Peak) performs the federally mandated reliability coordinator function for a majority of the Western Interconnection. While each transmission operator within the Western Interconnection operates its respective transmission system, Peak has the authority to direct specific actions to maintain reliable operation of the overall transmission grid.

1 https://www.wecc.biz/Pages/About.aspx
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Figure 8.4: 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 operations in support of 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 a number of committees, including its Operating Committee, the Reserve Sharing Group Committee, the Pacific Northwest Coordination Agreement (PNCA)
Coordinating Group, and the Transmission Planning Committee (TPC). ColumbiaGrid ColumbiaGrid formed on March 31, 2006. Its membership includes Avista, BPA, Chelan County PUD, Grant County PUD, Puget Sound Energy, Seattle City Light, Snohomish County PUD, and Tacoma Power. ColumbiaGrid 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 890 and 1000, ColumbiaGrid provides an open and transparent process to develop sub-regional transmission plans, assess transmission alternatives (including non-wires alternatives),
and provides a decision-making forum and cost-allocation methodology for new transmission projects. Northern Tier Transmission Group The Northern Tier Transmission Group (NTTG) formed on August 10, 2007. NTTG members include Deseret Power Electric Cooperative, Idaho Power, Northwestern Energy, PacifiCorp, Portland General Electric, and Utah Associated Municipal Power Systems. These members rely upon the NTTG committee structure to meet FERC’s coordinated transmission planning requirements. Avista’s transmission network has a number of strong interconnections with three of the six NTTG member systems. Due to
the geographical and electrical positions of Avista’s transmission network related to NTTG
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members, Avista participates in the NTTG planning process to foster collaborative
relationships with our interconnected utilities. Annual Transmission Planning Report
Avista’s Local Planning Report is the end product of both the Local Transmission Planning Process and the annual Planning Assessment. The Local Transmission Planning Process (Process) is outlined in Attachment K to Avista’s Open Access Transmission Tariff, FERC
Electric Volume No. 8. The Process identifies single system projects needed to mitigate future reliability and load-service requirements for the Avista Transmission System. The Planning Assessment is outlined in the NERC Reliability Standard TPL-001-4. The Planning Assessment determines where the Transmission System may not meet performance requirements as defined in the NERC Reliability Standards, and identifies Corrective Action Plans addressing how the performance requirements will be met. The Planning Assessment includes steady state contingency analysis, analysis of potential voltage collapse, and transient technical studies. Development of the Local Planning Report supports compliance with applicable NERC Reliability Standards as well as
satisfying necessary steps in the Local Transmission Planning Process. The Local Planning Report provides a 10-year Transmission System expansion plan by
including all Transmission System facility improvements. The following sections summarize information from this report and other studies done by the Transmission Planning group in the 2016 Assessment. Transmission System Study Results

Big Bend Area The Big Bend area transmission system performance will significantly improve upon completion of the Benton – Othello Station 115 kV Transmission Line Rebuild project. Improvements are made with reconductor projects, the Saddle Mountain 230 kV Station
project, and the addition of communication aided protection schemes.
Coeur d’Alene Area
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 will improve transmission system performance in the near and long term planning horizons. The Sandpoint Reinforcement Project and installation of capacitor banks at the St. Maries Substation are part of the long range plan for the area.
Lewiston/Clarkston Area
The transmission system in the Lewiston/Clarkston area performs well. Issues are limited primarily to N-1-1 outages2 on the 230 kV system and voltage exceeding facility ratings
2 Failure of two separate facilities.
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during light loading conditions. Installation of shunt reactors is recommended to mitigate
these issues.
Palouse Area
Completion of the Moscow 230 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.
Spokane Area Several performance issues exist with the present state of the transmission system in the
Spokane area and worsen with additional load growth. The staged construction of new 230 kV facilities at the Garden Springs 230 kV and Ninth and Central 230 kV Stations to reinforce the area will be required. Dependency on Beacon Station leaves the system
susceptible to performance issues for outages related to the station.
Short Circuit Study
This study identified six undersized 230 kV breakers at Noxon and two undersized 115 kV breakers at Sunset. A list of corrective actions plans developed to mitigate performance issues observed during the assessment are in the 2016 Annual Assessment document.3 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, it is anticipated that 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 for integrating potential new generation projects. These requests follow a strict FERC process, including three study steps 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 major projects
currently in Avista’s interconnection queue.4

3 http://www.oasis.oati.com/AVAT/AVATdocs/2016_Avista_System_Planning_Assessment.pdf
4 http://www.oasis.oati.com/AVAT/AVATdocs/GIP_Queue-V83.pdf
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Table 8.1: 2017 IRP Generation Study Transmission Costs
Project Size (MW) Cost Estimate ($ Millions)5 Kootenai County 100 2 Kootenai County 350 100
Rathdrum Station (115 kV) 26 <1 Rathdrum Station (115 kV) 50 <1 Rathdrum Station (115 kV) 200 55
Rathdrum Station (230 kV) 50 <1
Rathdrum Station (230 kV) 200 56 Thornton Station 100 <1 Othello Station 25 <1
Northeast Station (Spokane) 10 <1 Kettle Falls Station 10 <1 Long Lake 68 33 Monroe Street 80 2
Post Fall 10 <1 Post Falls 20 <1 Table 8.2: Third-Party Large Generation Interconnection Requests

Project Size (MW) Type Interconnection Location Proposed Date
#46 126 Wind Big Bend (WA) December 2018
#47 750 Wind Colstrip 500kV (MT) September 2018 #49 144 Wind Big Bend (WA) September 2018 #50 450 Pumped Hydro Colstrip 500kV (MT) December 2020 #51 300 Solar Broadview (MT) December 2020 #52 100 Solar Big Bend (WA) July 2020 #53 12 Solar Big Bend (WA) October 2018 #54 40 Solar Big Bend (WA) January 2019
Distribution Planning Avista continually evaluates its distribution system. The distribution system consists of approximately 347 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 the timber, mining, and agriculture industries. The goals of the distribution evaluation are to determine if there are capacity limitations on the system to serve current and future projected load for each individual feeder. The analysis also includes whether or not 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 then the best course of action is budgeted.
The primary role of electric distribution planning is to identify system capacity and service reliability constraints, and subsequently identify the best and lowest life-cycle cost
5 Cost estimates are in 2017 dollars and use engineering judgment with a 50 percent margin for error.
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solution. Traditionally this solution has centered on infrastructure upgrades such as poles,
wire, and cable. New technologies are emerging that may impact system analysis, including storage, photovoltaic (solar) and demand response. As these alternatives mature and evolve they are likely to play a role in our investment portfolio either as primary
solutions or capital deferment solutions. Avista has deployed several pilot projects with the intent of determining how best to meet customer needs and maintain a high degree of reliability now and in the future. To properly evaluate each feeder for new technologies, load data and system data is required. Quality load data is not available for all Avista feeders beyond monthly data logs recording peak load and energy. Without detailed load data, evaluating new technologies
is limited to portions of the system with the available data. Detailed data is required to validate whether new technologies solves current system constraint or just defers the constraint to a different time.
Currently, 195 of 347 feeders have three-phase SCADA (Supervisory Control and Data Acquisition) data available. We currently improve circuits as resource and budgeting allow
within our substation work schedule. As more demands beyond traditional capacity constraints and level of service requirements are placed on the grid, an increased amount of data is required to analyze and enhance the electric distribution system. Further, new load forecasting techniques such as spatial load forecasting will be required. This new forecasting method uses account GIS information regarding the feeder location and can help forecast specific feeder load growth taking into account 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 system.
Deferred Capital Investment Analysis New technologies such as storage, photovoltaics, and demand response programs could help the electrical system by deferring or eliminating other investments. This is dependent on the new technology 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 can help meet overall power supply peak load needs, but it may also improve local reliability by providing voltage support and deferring capital investment at the substation.
This section discusses the analysis for determining the capital investment deferment value for distributed energy resources (DERs). Unfortunately, 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 the peaks occur, whether they are near capacity or not, and how fast loads are growing in the area. It is not practical to have an estimate for each feeders in an IRP, but it is prudent to have a representative estimate to include in the resource selection analysis. For this analysis, Avista uses three representative feeders on three substations; 1) Barker Road, 2) Liberty Lake, and 3) Hallet & White. Each of these substations need capital investment due to growth in the next several years. Each location was fitted with an
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applicable storage device to determine how long the next investment could be deferred.
Then a financial analysis estimates the financial value to customers for deferring the investment. The value of deferred investment is determined by comparing the present value of the revenue requirement of the current plan versus the revenue requirement of
the alternative investment need when the storage device is installed. See Table 8.3 for the results of the analysis.
The value of the deferment is a range as it depends when the storage device is installed. The storage device has the greatest value when installed right before the investment is needed rather than years before. For this plan, $10 per kW-year is assumed for the IRP analysis. If distribution planning has a specific application for storage to meet distribution needs, the IRP group can provide the power supply benefits to add to the specific capital deferment analysis. Table 8.3: Capital Deferment Analysis
Substation Storage Capacity (MW)
Storage Energy (MWh)
Deferment Time (Years)
Value Range ($/kW-yr)
Barker Road 3.4 9.0 16 $5 - $16
Liberty Lake 6.0 43.0 21 $1 - $10
Hallet & White 1.7 10.5 9 $10 - $19
Grid Modernization In 2008, an Avista system efficiencies team of operational, engineering, and planning staff developed a plan to evaluate potential energy savings from transmission and distribution system upgrades. The first phase summarized potential energy savings from distribution feeder upgrades. The second phase, beginning in summer 2009, combined transmission system topologies with right sizing distribution feeders to reduce system losses, improve system reliability, and meet future load growth. The system efficiencies team evaluated several efficiency programs to improve urban and
rural distribution feeders. The programs consisted of the following system enhancements:
 Conductor losses;
 Distribution transformers;
 Secondary districts; and
 Volt-ampere reactive compensation.
The analysis combined energy losses, capital investments, and reductions in O&M costs resulting from the individual efficiency programs under consideration on a per feeder basis. This approach provided a means to rank and compare the energy savings and net
resource costs for each feeder. Building on the 2009 effort, a 2013 study assessed the benefits of distribution feeder automation for increased efficiency and operability. The Grid Modernization Program (GMP) combines the work from these system performance studies and provides Avista’s
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customers with refreshed system feeders with new automation capabilities across the
company’s distribution system. Table 8.4 shows the feeders currently planned for rebuild and their associated energy savings. The total energy savings from both re-conductor and transformer efficiencies for all completed feeders is approximately 1,930 MWh
annually. The GMP charter ensures a consistent approach to how Avista addresses each project. This program integrates work performed under various Avista operational initiatives, including the Wood Pole Management Program, the Transformer Change-Out Program, the Vegetation Management Program, and the Feeder Automation Program. The Distribution Grid Modernization Program includes replacing undersized and deteriorating
conductors, and replacing failed and end-of-life infrastructure materials including wood poles, cross arms, fuses, and insulators. It addresses inaccessible pole alignment, right-of-way, under-grounding, and clear-zone compliance issues for each feeder section, as
well as regular maintenance work including leaning poles, guy anchors, unauthorized attachments, and joint-use management. This systematic overview enables Avista to cost-effectively deliver a modernized and robust electric distribution system that is more
efficient, easier to maintain, and more reliable for our customers. Table 8.4: Planned Feeder Rebuilds
Feeder Area Year Complete Annual Energy Savings (MWh)
MIL12F2 Millwood, WA 2017 186
ORO1280 Orofino, ID 2017 112
PDL1201 Clarkston, WA 2017 189
TUR112 Pullman, WA 2018 233
HOL1205 Lewiston, ID 2018 TBD
RAT233 Rathdrum, ID 2019 472
SPI12F1 Northport, WA (Spirit) 2019 115
SPR761 Sprague, WA 2019 106
F&C12F1 Spokane, WA (Francis & Cedar) 2019 260
MIS431 Kellogg, ID 2023 257 Total 1,930

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9. Generation Resource Options
Introduction
Several generating resource options are available to meet future resource deficits. Avista can upgrade existing resources, build new facilities, or contract with other energy companies to meet its load obligations. This section describes resources Avista considered in the 2017 IRP to meet future needs. They mostly are generic, as actual resources identified through a competitive process may differ in size, cost, and operating characteristics due to siting, engineering, or financial requirements.
Assumptions Avista models only commercially available resources with well-known costs, availability, and generation profiles priced as if Avista developed and owned the generation. Resource options include natural gas-fired combined cycle combustion turbines (CCCT), simple cycle combustion turbines (SCCT), natural gas-fired reciprocating engines, large-scale onshore wind, energy storage, photovoltaic solar, hydroelectric upgrades, and thermal unit upgrades. Several other resource options described later in the chapter are not included in the PRS analysis, but discussed as potential resource options to respond
to a future resource acquisition. The IRP excludes potential contractual arrangements with other energy companies as an option in the plan, but such arrangements may actually offer a lower customer cost when a competitive acquisition process is completed.
The costs of each resource option include the transmission expenses described in Chapter 8 – Transmission & Distribution Planning. Levelized costs result from discounting nominal cash flows by a 6.46 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 2018 nominal dollars unless otherwise noted. Many renewable resources are eligible for federal and state tax incentives. Federal solar tax benefits begin to reduce beginning in 2020; federal production tax credits (PTCs) are no longer available unless meeting certain provisions. Incentives, to the extent they are
available, are included in IRP modeling.
Section Highlights
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Upgrades to Avista’s
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Avista relies on several sources including the NPCC, press releases, regulatory filings,
internal analysis, developer estimates, and Avista’s experience with certain technologies for its resource assumptions. The natural gas-fired plants use operating characteristics and cost information obtained from Thermoflow design software.
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 reality, 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 very infrequently during peak-load periods would appear more expensive than base-load CCCTs, even though peaking resources are lower cost when operating only a few hours each year. By allowing the expected costs to be divided by the expected amount of energy deliveries, levelized energy costs fairly compare non-
dispatchable renewable resources to the energy component of natural gas-fired resources because renewable technologies are typically not dispatchable. It is more difficult to estimate levelized costs for dispatchable resources because the amount of
MWh to levelize the costs over is debatable, such as its potential energy or economic dispatch. The levelized cost calculations include the following cost items for both the capacity and energy cost components.
 Capital Recovery and Taxes: Depreciation, return of and on capital, federal and state income taxes, property taxes, insurance, and miscellaneous charges such as uncollectible accounts and state taxes for each of these items pertaining to a generation asset investment.
 Allowance for Funds Used During Construction (AFUDC): The cost of money associated with construction payments made on a generation asset during construction.
 Federal Tax Incentives: The federal tax incentive in the form of a PTC, or investment tax credit (ITC), available to qualified generation.
 Fuel Costs: The average cost of fuel such as natural gas, coal, or wood per MWh of generation. Additional fuel price details are included in the Market Analysis
section.
 Fuel Transport: The cost to transport fuel to the plant, including pipeline capacity
charges.
 Fixed Operations and Maintenance (O&M): Costs related to operating the plant
such as labor, parts, and other maintenance services not based on production levels.
 Variable O&M: Costs per MWh related to incremental generation.
1 Storage technologies use a $ per kWh rather than $ per kW due to the resource is both energy and capacity limited.
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 Transmission: Includes depreciation, return on capital, income taxes, property taxes, insurance, and miscellaneous charges such as uncollectible accounts and state taxes for each of these items pertaining to transmission asset investments needed to interconnect the generator and/or third party transmission charges. Further information regarding interconnection cost are in Chapter 8.
 Other Overheads: Includes miscellaneous charges for non-capital expenses such as un-collectibles, excise taxes, and commission fees.
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. Table 9.1: Natural Gas-Fired Plant Levelized Costs per MWh
Advanced Large Frame CT $54 $156 220
Modern Large Frame CT $53 $154 186
Advanced Small Frame CT $60 $142 102
Frame/Aero Hybrid CT $43 $154 106
Small Reciprocating Engine Facility $38 $230 47
Modern Small Frame CT $55 $174 49
Aero CT $50 $187 45
1 on 1 Advanced CCCT $35 $230 362
1 on 1 Modern CCCT $34 $233 306
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 disadvantage of a CCCT is generation cost volatility due to reliance on natural gas, unless utilizing hedged fuel prices. CCCTs modeled in the IRP
are “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 250 MW and 350 MW each
depending on configuration and location. A two-on-one (2x1) CCCT plant configuration is possible with two turbines and one HRSG, generating up to 650 MW. Avista would need to share a 2 x 1 plant to take advantage of the modest economies of scale and efficiency
of a 2x1-plant configuration due to its large size relative to Avista’s needs. 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, if no water rights are available, a more capital-intensive and less efficient air-cooled technology may be used. For this IRP, Avista assumes water is
2 Peak credit is the amount of capacity a resource contributes at the time of system one hour peak load.
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available for plant cooling based on its internal analysis, but only enough for a hybrid
system utilizing the benefits of combined evaporative and convective technologies. This IRP models two types of CCCT plants, first a smaller 285 MW machine, and a larger
advanced 341 MW plant. Avista reviewed many CCCT technologies and sizes, and selected these plants due to their use in the Northwest. If Avista pursues a CCCT, a competitive acquisition process will allow analysis of other CCCT technologies and sizes. The most likely location 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 on the emission of carbon dioxide.3 CCCT site or 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.
The smaller CCCT’s heat rate is 6,720 Btu/kWh in 2016.4 The larger machine is 6,631 Btu/kWh. The plants include duct firing for seven percent of rated capacity at a heat rate of 7,912 and 7,843 Btu/kWh, respectively.
The IRP includes a three percent forced outage rate for CCCTs and 14 days of annual plant maintenance. The smaller plant can back down to 62 percent of nameplate capacity, while the larger plant can ramp down to 30 percent of nameplate capacity. The maximum capability of each plant is highly dependent on ambient temperature and plant elevation. The plan assumes a 30-year life absent capital upgrades for life extension.
The anticipated capital costs for the two CCCTs, located in Idaho on Avista’s transmission system with AFUDC on a greenfield site, are $1,174 per kW for the smaller machine and $1,122 per kW for the larger machine. These estimates exclude the cost of transmission
and interconnection. Table 9.1 shows levelized plant cost assumptions split between capacity and energy. 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. Natural Gas-Fired Peakers Natural gas-fired SCCTs and reciprocating engines, or peaking resources, provide low-cost capacity and are capable of providing energy as needed. Technological advances and their simpler design relative to CCCT plants allow them to start and ramp quickly, providing regulation services and reserves for load following and variable resources
integration. The IRP models frame, hybrid-intercooled, reciprocating engines, and aero-derivative
peaking resource options. The peaking technologies have different load following abilities, costs, generating capabilities, and energy-conversion efficiencies. Table 9.2 shows cost
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 has carbon dioxide mitigation fees for new plants.
4 Heat rates shown are the higher heating value.
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and operational characteristics based on internal engineering estimates. All peaking
plants assume 0.5 percent annual real dollar cost decrease and forced outage and maintenance rates. The levelized cost for each of the technologies is in Table 9.1. Table 9.2: Natural Gas-Fired Plant Cost and Operational Characteristics
Advanced Large Frame CT $654 $2.19 9,931 $3.73 1 203 203 $133
Modern Large Frame CT $684 $2.19 10,007 $2.67 1 170 170 $117
Advanced Small Frame CT $875 $3.28 11,265 $2.67 1 96 96 $84
Frame/Aero Hybrid CT $1,042 $3.28 8,916 $3.20 1 101 101 $105
Small Reciprocating Engine Facility
$1,229 $8.76 7,700 $3.20 5 9.3 47 $57
Modern Small Frame CT $1,349 $4.38 10,252 $2.67 1 45 45 $61
Aero CT $1,349 $6.57 9,359 $2.67 1 42 42 $57
1 x 1 Modern CCCT $1,148 $19.71 6,771 $4.00 1 341 341 $392
1 x 1 Advanced CCCT $1,207 $16.42 6,845 $3.20 1 286 286 $345
Firm natural gas fuel transportation is an electric reliability issue with FERC and 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. Firm transportation could be necessary where pipeline capacity becomes scarce during utility peak hours. However, pipelines near evaluated sites are not presently full or expected to become full in the near future. 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, and liquefied natural gas storage. Wind Generation
Governments promote wind generation with tax benefits, renewable portfolio standards, carbon emission restrictions, and stricter controls on existing non-renewable resources. In the Consolidated Appropriations Act 2016, HR 2029, section 301, passed December 2016, the U.S. Congress extended the PTC for wind through December 31, 2016, with
provisions allowing projects to qualify for a prorated credit after 2016 if commencing construction prior to 2019. For projects commencing construction in 2017, the PTC is
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reduced by 20 percent, 2018 is reduced by 40 percent, and 2019 reduced by 60 percent.
This IRP does not assume the PTC extends beyond this term, but does assume preferential five-year tax depreciation remains.
Wind resources benefit from having no emissions profile or fuel costs, but they are not typically dispatchable. On shore wind’s capital costs in 2018, including AFUDC, are $1,798 per kW for Washington projects and $1,636 per kW in Montana, with annual fixed O&M costs of $42.70 per kW-yr. Fixed O&M includes indirect charges to account for the inherent variation in wind generation, oftentimes referred to as wind integration. The cost of wind integration depends on the penetration of wind in Avista’s balancing authority and the market price of power. Wind integration in this IRP is $4.40 per kW-year in 2018.
These estimates come from Avista’s experience in the market and results from Avista’s 2007 Wind Integration Study. Wind capacity factors in the Northwest range between 25 and 40 percent depending on location. This plan assumes Northwest wind has a 37 percent average capacity factor. A statistical method, based on regional wind studies, derives a range of annual capacity factors depending on the wind regime in each year (see stochastic modeling assumptions for details). The expected capacity factor affects the levelized cost of a wind project. For example, a 30 percent capacity factor site could be $30 per MWh higher than a 40 percent capacity factor site holding all other assumptions equal.
As discussed above, levelized costs change substantially due to capacity factor, but can change more from tax incentives. Figure 9.1 shows nominal levelized prices with different
start dates, capacity factors, and availability of the ITC. For a plant installed in 2018 with utility ownership, the estimated “all-in” cost is $72 per MWh for 25 years, including the 20 percent REC apprenticeship adder for the EIA. Qualification for the adder requires 15
percent of construction labor by state-certified apprentices. It is possible for third party to Independent Power Producers to develop a project at a lower cost for the PPA, depending on turbine agreements, site conditions, and cost of capital. Typical PPA prices do not include integration or transmission, and may reflect a different cost recovery period. If Avista plans to acquire new wind generation, an RFP will help identify the least cost option to meet customer needs.
This IRP includes analysis on wind projects located in Montana. Based on Avista’s analysis, construction cost will be lower due to the absence of state sales tax and indications of higher quality wind speeds. Sites in Montana will require third party
transmission wheeling. Adding Montana wind will be less costly to integrate due to its different generation profile as compared to Palouse Wind, and it may add up to a 7.5
percent capacity contribution when combined with Palouse Wind’s expected output on to
meet the single-hour winter peak. For summer, the plan assumes the combined resources would add 3 percent of its capability. Montana wind, with transmission to deliver it to
Avista’s system, costs $83 per MWh as compared to $72 per MWh with the same capacity factor in the Northwest.
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Figure 9.1: Northwest Wind Project Levelized Costs per MWh
Photovoltaic Solar
Photovoltaic (PV) solar generation technology costs have fallen substantially in the last several years partly due to low-cost imports and from demand driven by renewable portfolio standards and tax incentives. Even with large cost reductions, IRP analyses
shows PV solar facilities still are uneconomic for winter-peaking utilities in the Northwest compared to other renewable and non-renewable generation options. This is due to its low capacity factor and lack of output during winter-peak periods. PV solar provides predictable daytime generation complementing the loads of summer-peaking utilities, though panels typically do not produce at full output during peak hours. Adding a substantial amount of PV solar to a summer peaking utility system reduces the peak hour recorded prior to the installation, but the peak hour shifts toward sundown when PV solar output is lower. As more PV solar enters a system, the on-peak resource contribution falls precipitously. Table 9.3 presents the peak credit by month with different
amounts of solar using output from the Rathdrum Solar Project. This table illustrates how
solar does not reduce Avista’s winter peak, reduces the summer peak, and is less effective at reducing peak with additional solar installations. Solar-thermal technologies can produce capacity factors as much as 30 percent higher than PV solar projects and can store several hours of energy for later use in reducing peak loads. However, solar thermal technologies do not lend themselves well to the Northwest due to their lack of significant generation in the winter and higher overall installation and operation costs; therefore, only PV solar systems are considered for this IRP.
72
84
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Table 9.3: Solar Capacity Credit by Month

Month 5 MW 25 MW 50 MW 100 MW 150 MW 200 MW 300 MW Jan 0% 0% 0% 0% 0% 0% 0% Feb 0% 0% 0% 0% 0% 0% 0% Mar 0% 0% 0% 0% 0% 0% 0%
Apr 28% 15% 11% 8% 6% 5% 3%
May 46% 46% 37% 26% 17% 13% 9%
Jun 39% 39% 36% 31% 25% 22% 19%
Jul 52% 49% 45% 43% 33% 27% 22%
Aug 40% 40% 40% 34% 32% 30% 24%
Sep 0% 0% 0% 0% 0% 0% 0%
Oct 0% 0% 0% 0% 0% 0% 0%
Nov 0% 0% 0% 0% 0% 0% 0%
Dec 0% 0% 0% 0% 0% 0% 0%

Utility-scale PV solar capital costs including AFUDC for a 50 MW (DC) system are $1,110 per kW for fixed panel and $1,165 per kW for single-axis tracking projects. A well-placed utility-scale single-axis tracking PV system located in the Pacific Northwest would achieve a first-year capacity factor of approximately 18 percent and a fixed panel system would achieve 15 percent. PV solar output degrades over time; the IRP de-rates solar generation output by one-half percent each year. The federal government’s 30 percent tax credit begin phasing out after 2019. Projects starting construction in 2020 have a 26
percent ITC, 22 percent for 2021 projects, and 10 percent for any projects afterward. Figure 9.2 shows the levelized costs of PV solar resources, including applicable federal
and state incentives, on-line dates, and capacity factors. Like wind projects, independent power producers may have lower costs than utilities due to panel agreements, cost of capital and the ability to using federal incentives to directly lower upfront costs, rather
than amortizing tax credits over the life of the asset. The costs in Figure 9.2 show the price advantage of IPP development as far as transferring benefits from the ITC directly to customers. IRP modeling in this IRP assumes the ITC would be a credit to the cost of the project rather than amortized over the life of the asset. The State of Washington offers a number of incentives for solar installations. Plants less than five megawatts count double toward Washington’s EIA. The state also offers
substantial financial incentives for consumer-owned solar. Consumer-owned solar counts in reductions in Avista’s retail load forecast.

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Figure 9.2: Solar Nominal Levelized Cost ($/MWh)
Energy Storage Increasing solar and wind generation makes energy storage technologies attractive from an operational perspective. Storage could smooth out renewable generation variability, absorb oversupply, and assist in load following and regulation needs. The technology could help meet peak demand, provide voltage support, relieve transmission congestion,
take power during oversupply events, and supply other non-energy needs for the system. The IRP considered several storage technologies, including pumped hydroelectric, lead-acid batteries, lithium-ion batteries, vanadium flow batteries, flywheels, compressed air,
liquefied air, and gravity systems. For modeling purposes, the IRP uses two plant types: a 1x3-storage facility and a 1x6. Meaning, for each MW of capacity, it has three or six MWh of storage. Modeling each storage technology would not provide additional insight as a comparison to other supply options because Avista’s capacity needs are not urgent, the technology is changing rapidly, and each has different losses, lifespan and flexibility. Modeling of storage’s non-power supply benefits is still in development. Although Avista is attempting to estimate as many of these values as possible. For example, Chapter 8 discusses the methodology to estimate the value of deferred distribution capital investment. The IRP
includes a value for market arbitrage and providing ancillary services such as regulation, spinning, and non-spinning reserves. Avista is developing an evaluation for estimating the storage benefit for network services such as reliability, voltage support and frequency
response (not all storage options can provide this service). Each of these benefits are
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part of the Clean Energy Funds/PNNL partnership to estimate values for storage. A report
will be available in the spring of 2018. Storage may become an important part of the nation’s electricity grid if the technology
overcomes a number of physical, technical, and economic barriers. First, existing technologies consume a significant amount of electricity relative to their output through conversion losses. Second, equipment costs are still high, but falling, at nearly three times
the initial cost of a natural gas-fired peaking plant. Peaking plants provide many of the same capabilities without the electricity consumption characteristics of storage. Storage costs will decline over time and Avista will monitor the technologies as part of the IRP process. Third, the current scale of most storage projects is relatively small, limiting their applicability to utility-scale deployment. Avista installed a vanadium flow battery in Pullman, Washington to learn more about
storage technology. The Turner Energy Storage Project provides insight about the
technology’s reliability, potential benefit to the transmission and/or distribution systems, and potential power supply benefits including oversupply events. The battery has 1.2
megawatts of power capability and 3.5 megawatt-hours of energy storage. A Washington State research and development grant partially funded this project.
Turner Energy Storage Project, Pullman, WA As part of the Clean Energy Funds 2 grants, Avista proposes to develop two additional storage projects in the University District of downtown Spokane. One 500 kW project with two MWh of storage and the other project 100 kW with 0.5 MWh of storage. At the time
of this IRP’s drafting these projects are out to bid and expected to begin operation in late 2018.
The Northwest might be slower in adopting storage technology relative to other regions in the country. The Northwest hydroelectric system already contains a significant amount of storage relative to the rest of the country. However, as more capacity consuming
renewables enter the electric grid, new storage technologies might play a significant role
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in meeting the need for additional operational flexibility if upfront capital costs and
operational losses continue to fall. In addition to capital costs, storage project O&M costs are $20 per kWh-year levelized,
and recharge costs use off-peak Mid-Columbia energy prices. Levelized storage project costs are inaccurate as storage projects do not create megawatt hours; in fact, they consume megawatt hours with 15 to 20 percent or more of their charge being lost. Avista’s experience with vanadium flow storage has losses from 30 to 50 percent. This IRP assumes 17 percent losses over its 20 year expected life. Storage costs are typically shown in $/kWh due to the energy limitation of the project rather than $ per kW. The capital cost in 2018 dollars including AFUDC is $713 per kWh for the 1x3 project and $642 for the 1x6 project. By 2025, the costs fall to $573 and $516 per kWh respectively. Other Generation Resource Options
Many resources were not specifically included as resource options in this IRP. These resources include biomass, geothermal, co-generation, nuclear, offshore wind, landfill gas, and anaerobic digesters. 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 available. Exclusion from the PRS does not necessarily exclude non-modeled technologies from
Avista’s future portfolio. The non-modeled resources can compete with resources identified in the PRS through competitive acquisition processes. Competitive acquisition processes identify technologies to displace resources otherwise included in the IRP
strategy. Another possibility is acquisition through PURPA mandates. PURPA provides developers the ability to sell qualifying power to Avista at set prices and terms.5 Woody Biomass Generation Woody biomass generation projects use waste wood from lumber mills or forest management. In the generation process, a turbine converts boiler-created steam into electricity. A substantial amount of wood fuel is required for utility-scale generation.
Avista’s 50 MW Kettle Falls Generation Station consumes over 350,000 tons of wood waste annually, or 48 semi-truck loads of wood chips per day. It typically takes 1.5 tons of wood to make one megawatt-hour of electricity; the ratio varies with the moisture content of the fuel. The viability of another Avista biomass project depends on the availability and cost of the fuel supply. Many announced biomass projects fail due to lack of a long-term fuel source. If an RFP identifies a potential woody biomass project, Avista
will consider it for a future resource. Geothermal Generation
Geothermal energy provides predictable capacity and energy with minimal carbon dioxide 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
5 Rates, terms, and conditions are available at www.avistautilities.com under Schedule 62.
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projects are likely to develop. Geothermal energy struggles to compete economically due
to high development costs stemming from having to drill several holes thousands of feet
below the earth’s crust; each hole can cost over $3 million. Ongoing geothermal costs are low, but the capital required locating and proving a viable site is significant. Further, there
are no good geothermal resource sites in or near Avista’s service territory or transmission system. Landfill Gas Generation Landfill gas projects generally use reciprocating engines to burn methane gas collected at landfills. The Northwest has developed many landfill gas resources. The costs of a landfill gas project depend on the site specifics of a landfill. The Spokane area had a
project on one of its landfills, but was retired after the fuel source depleted to an unsustainable level. Much of the Spokane area no longer landfills its waste and instead uses the Spokane Waste to Energy Plant. Nearby in Kootenai County, Idaho, the
Kootenai Electric Cooperative developed the 3.2 MW Fighting Creek Project. Using publically available costs and the NPCC estimates, landfill gas resources are economically promising, but are limited in their size, quantity, and location. Further, due
to falling wholesale market pricing, many landfills are considering cleaning the gas to create pipeline quality gas. This form of renewable gas has become an option for natural gas utilities to offer a renewable gas alternative. 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. These facilities tend to be significantly smaller than utility-scale generation projects, at less than five megawatts. Most 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 greatly, though 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 facility. Anaerobic digesters may opt to clean the gas to make to pipeline quality to offer a clean gas alternative.
Small Cogeneration Avista has few industrial customers with loads significantly large enough to support a
cogeneration project. If an interested customer was inclined to develop a small cogeneration project, it could provide benefits including reduced transmission and distribution losses, shared fuel, capital, and emissions costs, and credit toward
Washington’s EIA efficiency targets.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 125 of 205
Another potentially promising option is natural gas pipeline cogeneration. This technology
uses waste-heat from large natural gas pipeline compressor stations. In Avista’s service territory few compressor stations exist, 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 determined 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 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 particular project. The best method for the utility to
acquire this technology is through the PURPA process. Nuclear
Avista does not include nuclear plants as a resource option in the IRP 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. Nuclear resources could be in Avista’s future only if other utilities in the Western Interconnect incorporate nuclear power in their resource mix and offer Avista an ownership share 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 the needs of smaller utilities.
Offshore Wind Avista does not include offshore wind resources in this IRP due to the current availability of onshore wind resource options with lower prices and without third party transmission services. Offshore wind is a proven technology outside of the US, so far only one project is operational in the U.S. Avista will continue to monitor this technology as its cost and efficiency change.
Coal The coal generation industry is at a crossroads. In many states, like Washington, new
coal-fired plants are extremely unlikely due to emission performance standards and the shortage of utility scale carbon capture and storage projects. Federal guidelines regarding
coal are uncertain given the current EPA administration’s review of section 111(b) of the CAA and the CPP. The risks associated with future carbon legislation and projected low natural gas costs make investments in this technology highly unlikely.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 126 of 205
Hydroelectric Project Upgrades and Options
Avista continues to upgrade its hydroelectric facilities. The latest hydroelectric upgrade added ten megawatts to the Nine Mile Falls Development in 2016. Figure 9.3 shows the
history of upgrades to Avista’s hydroelectric system. Avista added 46.8 aMW of
incremental hydroelectric energy between 1992 and 2016. Upgrades completed after 1999 can qualify for the EIA, thereby reducing the need for additional renewable energy options.
Figure 9.3: Historical and Planned Hydro Upgrades

Construction of the Spokane River hydroelectric project occurred in the late 1800s and early 1900s, when the priority was to meet then-current loads. The developments therefore do not capture a majority of 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 developments and estimated costs for generation upgrade options. Each upgrade option should 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 project water rights. Table 9.4
summarizes the upgrade options. The upgrades will compete against other renewable options when more renewables are required.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 127 of 205
At the time of this IRP, the company is developing a long-term strategy for Post Falls. The
current scope of the project is to replace the current generating equipment with newer technology. Part of this IRP’s Action Plan will be to report on the redevelopment plan. Table 9.4: Hydroelectric Upgrade Options
Resource Monroe Street/Upper Falls
Long Lake Cabinet Gorge
Incremental Capacity (MW) 80 68 110
Incremental Energy (MWh) 237,352 202,592 161,571
Incremental Energy (aMW) 27.1 23.1 9.2
Peak Credit (Winter/ Summer) 31/0 100/100 0/0
Capital Cost ($2018 Millions) $196 $182 $290 Levelized Energy Cost ($2018/MWh) $93 $122 $200
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 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 replaces the existing four-unit powerhouse with four larger units totaling 120 MW, increasing capacity by 32 MW. The other two alternatives develop a second powerhouse with a penstock beginning from a
new intake structure downstream of the existing saddle dam. One powerhouse option was a single 68 MW turbine project. The second was a two-unit 152 MW project. The best alternative in the study was the single 68 MW option. Table 9.4 shows upgrade costs and
characteristics. Monroe Street/Upper Falls Second Power House Avista replaced the powerhouse at its Monroe Street development on the Spokane River in 1992. There are three options to increase its capacity. Each would be a major undertaking requiring substantial cooperation with the City of Spokane to mitigate disruption in Riverfront and Huntington parks and downtown Spokane during
construction. The upgrade could increase plant capacity by up to 80 MW. To minimize impacts on the downtown area and the park, a tunnel drilled on the east side of Canada Island could avoid excavation of the south channel. A smaller option would add a second
40 MW Upper Falls powerhouse, but this option would require south channel excavation. A final option would add a second Monroe Street powerhouse for 44 MW. Cabinet Gorge Second Powerhouse Avista is exploring the addition of a second powerhouse at the Cabinet Gorge development site to mitigate total dissolved gas and produce additional electricity. A new
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 128 of 205
110 MW underground powerhouse would benefit from an existing diversion tunnel around
the dam built during original construction. This resource does not add any peak capacity credit due to the water right limitations of the license. The resource only creates additional energy during spring runoff.
Thermal Resource Upgrade Options
The 2015 IRP identified several thermal upgrade options for Avista’s fleet. Some options,
such as the Cold Day Controls and Advanced Hot Gas Path at Coyote Springs 2, are already in service. This plan contains new ideas to increase generating capability at
Avista’s thermal generating resources. No costs are presented in this section, as pricing is sensitive to third-party suppliers. Northeast CT Water Injection This is a water injected NOx control system allowing the firing temperature to increase and thereby increasing the capacity at the Northeast CT by 7.5 MW. Rathdrum CT Supplemental Compression
Supplemental compression is a new technology developed by PowerPhase LLC that increases airflow through a combustion turbine compressor 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 corresponding to a five MW increase in output. Rathdrum CT Inlet Evaporation Installing a new inlet evaporation system will 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. At this time, Avista could spend additional
capital and upgrade the unit by five megawatts rather than replace it with in-kind technology. Kettle Falls Fuel Stabilization The wood burned at Kettle Falls varies in moisture content, and dryer fuel burns more efficiently. A fuel drying system added to the fuel handling system would allow the boiler to operate at a higher efficiency point, increasing plant capability by three megawatts.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 129 of 205
Ancillary Services Valuation
IRPs traditionally model the value of resources using hourly models. This method provides a good approximation of resource value, but it does not provide a value for the intra-hour or ancillary services needs of a balancing area. Ancillary services modeled in
the IRP include spinning and non-spinning reserves, regulation, and load following. Spinning and non-spinning reserve obligations together equal three percent of load and three percent of on-line generation, as required by regional standards. Half of the
reserves must synchronize to the system and half must be capable of synchronizing within ten minutes. Regulation meets instantaneous changes in load or resources with plants responding to the change using automatic generating control. Load following covers load changes within the hour, but for movements occurring across a timeframe greater than ten minutes. Avista developed a new tool, called the Avista Decision Support System (ADSS), for use in operations and long-term planning. This model is a mixed-integer linear program simulating Avista’s system. It optimizes a set of resources to meet system load and ancillary services requirements using real-time information. The tool uses both actual and
forecasted information regarding the surrounding market and operating conditions to provide dispatch decisions, but can also use historical data to simulate benefits of certain system changes. ADSS uses historical data sets to estimate ancillary services values for
storage and natural gas-fired resources. Storage As intermittent resources grow in size, there is potential for the existing system not being robust enough to integrate the resources and handle oversupply of renewable energy. To address this concern, governments and utilities are promoting and investing in storage technology. Today storage has a limited role due to cost and technology development. This analysis uses the study competed for the 2015 IRP to determine the potential
financial value storage brings to Avista’s power supply costs. The study includes several storage capacities with storage to peak ratio of three to one and 85 percent efficiency.
Table 9.5 shows the values brought to the power supply system for each storage capacity size. These values are to the Avista system only and do not represent the value to other systems or non-power supply benefits. Avista has a deep resource stack of flexible resources and adding additional flexible resources do not necessarily add value unless sold to third parties. The values shown in Table 9.5 include margin from several value streams including operating reserves, regulation, load following, and arbitrage. Arbitrage optimizes the battery to charge in low price periods and discharge when prices are higher. Of the values shown in Table 9.5, arbitrage represents the largest value stream. Figure 9.4 shows the
five value streams for power supply benefits. Load following and arbitrage represent 92 percent of the value to Avista.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 130 of 205
Table 9.4: Storage Power Supply Value

Storage Capacity (MW)
Annual Value Annual $/kW Value
35 $1,201,590 $34
30 $1,024,569 $34
25 $923,291 $37
10 $381,407 $38
5 $189,000 $38
1 $36,862 $37
Figure 9.4: Storage’s Value Stream
Natural Gas-Fired Facilities Natural gas-fired facilities can provide energy and ancillary services. This study looks at
their incremental ancillary services value to the system as prepared for the 2015 IRP. The values do not represent the value for current resources of similar technology, but only the incremental value of a new facility. This study assumes 100 MW resource increments in
2020. Table 9.6 shows the results of the analysis. The incremental values for these resources are marginal due to the limited need for these types of services. The study assumes each facility has different operating capabilities. For example, diesel back-up can only provide non-spin reserves as it is for emergency use only, while the LMS 100 may provide non-spinning reserves, spinning reserves, regulation, and load following if operating.
Arbitrage, 64%
Load Following, 28%
Spin & Non-Spin Reserves, 5%
Regulation, 2%
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 131 of 205
Table 9.5: Natural Gas-Fired Facilities Ancillary Service Value

Resource Type Capabilities Annual $/kW Value
CCCT Load Following/ Spin6, Regulation $0.00
LMS 100 Load Following/ Spin, Non-Spin/ Regulation $1.12
Reciprocating Engines Load Following/Spin/Non-Spin $0.61
Diesel Back-Up Non-Spin $0.00
An action item from this IRP is to determine the intra hour valuation of these services for both storage and natural gas-fired peakers using historical data closer to the 2019 IRP
release date and implementing new modeling techniques including intra hour modeling.
Avista’s DSS model at the time of the IRP is not capable of intra hour modeling, but it is in process of adding this functionality.

6 Fast start CCCTs may have some non-spin reserve capability.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 132 of 205

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 133 of 205
10. Market Analysis
Introduction This section describes the electricity, natural gas, and other markets studied in the 2017 IRP. It contains price risks Avista considers to meet customer demands at the lowest reasonable cost. The analytical foundation for the 2017 IRP is a fundamentals-based electricity model of the entire Western Interconnect. The market analysis evaluates potential resource options on their net value within the wholesale marketplace, rather than the summation of their installation, operation, maintenance and fuel costs. The Preferred Resource Strategy (PRS) analysis uses these net market values to select
future resource portfolios. Understanding market conditions in the Western Interconnect is important because
regional markets are highly correlated due to large transmission linkages between load centers. This IRP builds on prior analytical work by maintaining the relationships between the sub-markets within the Western Interconnect and the changing energy market values of company-owned and contracted-for resources. The backbone of the analysis is an electricity market model. The model, AURORAXMP, emulates the dispatch of resources to serve loads across the Western Interconnect given fuel prices, hydroelectric conditions, and transmission and resource constraints. The model’s
primary outputs are electricity prices at key market hubs (e.g., Mid-Columbia) and resource dispatch including the resources costs, market value and greenhouse gas emissions.

Marketplace
AURORAXMP is a fundamentals-based modeling tool used by Avista to simulate the Western Interconnect electricity market. The Western Interconnect includes states west of the Rocky Mountains, the Canadian provinces of British Columbia and Alberta, and the Baja region of Mexico as shown in Figure 10.1. The modeled area has an installed resource base of approximately 240,000 MW.
Section Highlights
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 134 of 205
Figure 10.1: NERC Interconnection Map
The Western Interconnect is separate from the Eastern and ERCOT interconnects to the east except for eight DC inverter stations. It follows operation and reliability guidelines administered by the Western Electricity Coordinating Council (WECC). Avista modeled the WECC electric system as 17 zones based on load concentrations and transmission constraints. After extensive study in prior IRPs, Avista models the Northwest region as a single zone because this configuration dispatches resources in a manner consistent with historical operations. Table 10.1 describes the specific zones
modeled in this IRP. Table 10.1: AURORAXMP Zones
Northwest- OR/WA/ID/MT Southern Idaho
COB- OR/CA Border WyomingEastern Montana Southern California
Northern California ArizonaCentral California New Mexico
Colorado AlbertaBritish Columbia South Nevada
North Nevada Baja, MexicoUtah
Western Interconnect Loads The 2017 IRP relies on a load forecast for each zone of the Western Interconnect. Avista uses utility resource plans and regional plans to quantify load growth across the west. These plans include estimates regarding energy efficiency, customer-owned generation, plug-in electric vehicles and demand response reductions. Forecasting future energy use is difficult because of large uncertainties with the long-term drivers of future energy use.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 135 of 205
Figure 10.2 shows regional load growth estimates. The total of the forecasts show
Western Interconnect loads rising nearly 0.85 percent annually over the next 20 years. On a regional basis, the Northwest grows at 0.77 percent, California at 0.25 percent, and the Rocky Mountain States at 1.63 percent. Canada is 1.5 percent. From a system
reliability perspective, regional peak loads grow at similar levels. Figure 10.2: 20-Year Annual Average Western Interconnect Energy
Resource Retirements The resource mix constantly changes as new resources start generating and older resources retire. In prior IRPs, much of the existing fleet continued to serve loads in combination with new resources. Many companies are now choosing to retire older plants to comply with environmental regulations and economic changes. Most plant closures are once-through-cooling (OTC) facilities in California and older coal
technology throughout North America. Several states are developing rules to restrict or eliminate certain generation technologies. In California, all OTC facilities require retrofitting to eliminate OTC technology or the plant must retire. Over 14,200 MW of OTC natural gas-fired generators in California likely will retire and need replacement in the IRP timeframe. The IRP assumes the closure of OTC plants with identified shutdown dates from their utility owners’ IRPs and announcements. Elimination of OTC plants in California will eliminate older technology presently used for reserves and high demand hours. Replacement plants will be expensive for California customers, but they will have a more modern,
efficient and flexible generation fleet. Coal-fired facilities face increasing regulatory scrutiny. In the Northwest, the Boardman
and Centralia coal plants will retire by the end of calendar years 2020 and 2025
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 136 of 205
respectively. Recently Colstrip 1 & 2 announced closure by 2022, for a reduction total of
about 2,621 megawatts. Other coal-fired plants throughout the Western Interconnect have announced plant closures, including Four Corners, Carbon, Arapahoe, San Juan, Reid Gardner, Dave Johnson, North Valmy, and Intermountain. The Nevada legislature
successfully placed into law a plan to retire all in-state coal plants, and other utilities appear poised to retire many plants as indicated in recent IRPs. Over the next 20 years, roughly 43 percent of the US Western Interconnection coal fleet retires in the Expected
Case. In total, announced retirements for all generation technologies, as shown in Figure 10.3, equal approximately 25 gigawatts between 2017 and 2037. Avista did not forecast additional coal retirements beyond official announcements prior to development of the Expected Case. Figure 10.3: Resource Retirements (Nameplate Capacity)
New Resource Additions New resource capacity is required to meet load growth and replace retiring power plants over the next 20 years. The generation additions meet capacity, energy, ancillary services and Renewable Portfolio Standards (RPS). Only natural gas-fired peaking and CCCT plants, storage, solar, and wind facilities are in the plan. The IRP does not include new nuclear or coal plants over the forecast horizon. The model objective is to meet capacity and renewable energy targets, but actual resources constructed may differ. Many states have RPS requirements promoting renewable generation to reduce
greenhouse gas emissions, provide jobs, and diversify energy mixes. RPS legislation generally requires utilities to meet a portion of their load with qualified renewable resources. No federal RPS mandate exists presently; therefore, each state defines RPS
obligations differently. AURORAXMP now models RPS levels explicitly. The RPS
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 137 of 205
requirements are loaded into the model and the model selects resources to satisfy state
laws. Figure 10.4 illustrates new capacity and RPS additions made in the modeling process. Nearly 98 GW will be required to meet the renewable and capacity requirements for the US system. Wind and solar facilities meet most renewable energy
requirements. Geothermal, biomass, and hydroelectric resources provide limited RPS contributions;
given their large range in costs and availability, these resources are not included in the capacity expansion study. Due to its low capacity factor, large quantities of solar capacity are necessary to make a meaningful contribution. Figure 10.4: Cumulative WECC Generation Resource Additions (Nameplate Capacity)
In total, 61,000 MW of new utility and consumer-owned renewable generation will
pressure afternoon peak pricing lower and move peak load requirements later in the day. Potential for oversupply in shoulder months in California will increase imports to the Northwest and other markets. The largest resource additions expected in the west are solar and natural gas-fired generation. Solar is the largest driver of new resource additions due to RPS requirements and the reduction in costs compared to alternative renewable resources. Most natural gas-fired technology will be peakers to provide a low cost flexible capacity to balance intermittent power generation and not burden customers with high capacity costs. Given the large amount of future renewables on the system, wholesale power prices will remain low and costs of larger baseload plants built to meet peak capacity requirements will be difficult to extract from the wholesale market,
placing a burden on utility ratepayers or independent power producer’s shareholders. Based on these market fundamentals and the requirement to have a reliable system where peakers rather than combined cycle plants will play a larger role in the future.

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 138 of 205
A new entrant into the resource forecast is storage technology. At the time of the IRP
analysis, the capacity expansion model cannot model the economic additions of storage; current storage additions for the most part either are mandated or pilot projects. This forecast cautiously includes 5,500 MW of new storage capacity over the
20-year period. Given the changes in storage costs and policy, Avista will continue to monitor this technology to determine if a larger level of market penetration is likely. The Northwest market needs new capacity resources in the 2021/22 period. This study includes nearly 7,000 MW of new natural gas-fired generation to meet load growth and replace retiring resources across the four Northwest states. As for renewable requirements, new generation will continue to consist of wind, but Avista expects movement to solar as costs decrease allowing solar to grow at a greater pace than wind energy. Table 10.2 shows the amount of new renewables added to the Northwest by the end of 2037. Also included in this analysis, is consumer driven renewables. These
additions, amounting to one percent of load meet customer demand for renewables as part of a utility’s renewable energy offerings. Table 10.2: Added Northwest Renewable Generation Resources
Resource Type Capacity (MW)
Wind 4,100 Utility- Solar 4,800 Customer- Solar 1,922
Fuel Prices and Conditions
Fuel cost and availability are some of the most important drivers of the wholesale electricity marketplace and resource values. Some resources, including geothermal and biomass, have limited fuel options or sources, while natural gas has greater potential.
Hydroelectric, wind, and solar resources benefit from free fuel, but are highly dependent on weather and siting opportunities. Natural Gas The natural gas industry continues its fundamental shift towards hydraulic fracturing and shale resources. New methods and technology continue to increase efficiency and production from wells. Over the next 25 years, demand in the residential, commercial,
and industrial natural gas markets should slightly decline. At the same time, exports to Mexico and for LNG will ramp up as demand for natural gas-fired generation in Mexico and completion of LNG plants materialize.
Natural gas used for power generation is growing due to its ability to support variable output from renewable energy and as a replacement for coal plant retirements. The fuel
of choice for new base-load and peaking generation continues to be natural gas. Natural gas has a history of significant price volatility, generally attributed to weather related demand and supply issues. The long-term forecasted supply for natural gas shows the average daily supply will increase to meet new demand through 2050.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 139 of 205
Avista uses forward market prices and a forecast from a prominent energy industry
consultant to develop the natural gas price forecast for this IRP. Based on these forecasts, the levelized nominal price is $4.20 per dekatherm (Dth) at Henry Hub (shown in Figure 10.5 as the green bars). The pricing methodology used to create a
fundamental price forecast follows:
 2018-2019: 100 percent market;
 2020: 75 percent market, 25 percent consultant;
 2021: 50 percent market, 50 percent consultant;
 2022: 25 percent market, 75 percent consultant; and
 2023-2037: 100 percent consultant.
Figure 10.5: Henry Hub Natural Gas Price Forecast
Price differences across North America depend on demand at the major trading hubs and pipeline constraints existing between them. Table 10.3 presents western natural gas basin differentials from Henry Hub prices. Prices converge over the course of the study as new pipelines and sources of natural gas materialize. To illustrate the seasonality of natural gas prices, monthly Stanfield price shapes are in Table 10.4 for selected forecast years.

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 140 of 205
Table 10.3: Natural Gas Price Basin Differentials from Henry Hub
Basin 2018 2020 2025 2030 2035 Stanfield 93% 93% 96% 97% 100% Malin 96% 96% 97% 99% 101% Sumas 90% 89% 92% 97% 100% AECO 73% 74% 84% 91% 92% Rockies 95% 94% 96% 97% 99% Southern CA 102% 103% 103% 102% 103%
Table 10.4: Monthly Price Differentials for Stanfield from Henry Hub
Month 2018 2020 2025 2030 2035 Jan 97% 95% 97% 98% 102% Feb 97% 95% 97% 98% 102% Mar 93% 94% 96% 98% 100% Apr 91% 94% 96% 97% 99%
May 91% 91% 95% 96% 99%
Jun 91% 91% 94% 96% 98%
Jul 92% 91% 94% 95% 98%
Aug 92% 93% 95% 96% 98%
Sep 93% 94% 95% 98% 99%
Oct 92% 94% 96% 97% 100%
Nov 95% 95% 97% 99% 102%
Dec 97% 95% 97% 98% 101%
Coal This IRP assumes no new coal plants in the Western Interconnect, but models existing plants as part of the electric system unless scheduled for retirement. Existing coal facilities typically have medium to long-term fuel contracts in place and many have ties to oil prices due to transportation costs. These contracts are not publically available. For each coal plant, Avista uses publically available coal prices filed with FERC, and then uses an average annual price increase over the IRP timeframe of 1.2 percent for railed coal and 1.4 percent for mine mouth coal based on data from the Energy Information Administration1. For Colstrip Units 3 and 4, Avista used escalation rates based on expectations from existing and expectations of future contracts. Hydroelectric The Northwest U.S., British Columbia and California have substantial hydroelectric
generation capacity. A favorable characteristic of hydroelectric power is its ability to provide near-instantaneous generation up to and potentially beyond its nameplate rating. Hydro 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
1 Energy Information Administration’s Annual Energy Outlook 2016, reference case.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 141 of 205
generation resources. The key drawback to hydroelectric generation is its variable and
limited fuel supply. This IRP uses an 80-year hydroelectric data record from the 2014 BPA rate case. The
study provides monthly energy levels for the region over an 80-year hydrological record spanning 1928 to 2009. Many IRP studies use an average of the hydroelectric record, whereas stochastic studies randomly draw from the record, as the historical distribution of hydroelectric generation is not normally distributed. Avista does both. Figure 10.6 shows the average hydroelectric energy of 15,720 aMW in the northwest, 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 12,489 aMW (-21 percent) and a 90th percentile water year of 18,586 aMW (+18 percent).
AURORAXMP maps each hydroelectric plant to a load zone, creating a similar energy shape for all plants in the load zone. For Avista’s hydroelectric plants, AURORAXMP
uses the output from its own proprietary software with a more accurate representation of operating characteristics and capabilities. AURORAXMP represents hydroelectric plants using annual and monthly capacity factors, minimum and maximum generation levels,
and sustained peaking generation capabilities. The model’s objective, subject to constraints, is to shift hydroelectric generation into peak load hours to maximize the value of the system consistent with actual operations. Figure 10.6: Northwest Expected Energy
Wind New wind resources satisfy a significant share of western renewable portfolio standards over the IRP timeframe. These additions increase competition for the remaining higher-quality wind sites. Similar to how AURORAXMP maps each hydroelectric plant to a load
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 142 of 205
zone, the capacity factors in Figure 10.7 are averages for each zone. The IRP uses
capacity factors from a review of the BPA and the National Renewable Energy Laboratory (NREL) wind data sets. Figure 10.7: Regional Wind Expected Capacity Factors
Greenhouse Gas Emissions and the Clean Power Plan
Greenhouse gas, or carbon emissions, regulation is a significant uncertainty for the electricity industry because of reliance on carbon-emitting generation and the potential of regulation to increase wholesale prices. Regulation may require the reduction of carbon emissions at existing power plants, the construction of low- and non-carbon-emitting technologies, and for changes to existing operations. Between 2008 and 2015, western states carbon emissions from generation dropped nearly 13 percent due to reduced loads and less coal generation. Future carbon emissions could fall due to fundamental market changes or regulation. In 2014, the EPA released the draft Clean Power Plan (CPP) under section 111(d) of the
CAA to reduce emissions from existing plants. With a new Federal Administration, the future of regulation under 111(d) may change; at the same time, state-level emission reduction policies may move forward. Washington’s Clean Air Rule (CAR) caps
emissions for facilities emitting more than 100,000 metric tons per year, and reduces the emissions threshold by 5,000 metric tons per year, until covering all entities emitting over 70,000 metric tons by 2035. The Washington Commission may implement rules regarding RCW 70.235, from the Executive Order 07-02. Other states, such as Oregon, are also considering carbon emissions limitations at the state legislature. Without final or specific rules and regulations, modeling the impact of future policies is difficult, but this plan includes specific assumptions. Due to uncertainty and the likelihood of
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 143 of 205
greenhouse gas regulations, this IRP used the CPP goals to guide the development of
the emission reduction forecast of this IRP. For the Expected Case, the CAR limits plant level emissions in Washington. The Clean
Air Rule identifies specific reductions to plants over a glide path by 2035. As an alternative to reductions, emission credits or RECs from Washington State may satisfy compliance obligations. The CAR monitors compliance at three-year intervals.
Washington State may generate up to the cap each year based on the three-year average generation between 2012 and 2015. Each year the cap declines. For covered plants, the total allowance is for the group rather than the individual facility providing for allowance trading. The Department of Ecology intends to set baseline emission levels and reduction targets for new plants covered under the CAR. The Oregon emissions policies, beyond the requirements in SB 1547 ending the use of
coal to serve Oregon loads by 2030 and an increased RPS reaching 50 percent by 2040, are in development at the writing of this IRP. However, emissions are not likely to increase long term. This IRP assumes emissions fall by 30 percent compared to 2015
by 2025. The IRP assumes Idaho emissions follow the CPP emission intensity goals. Additional details about the state-level emissions reductions programs are in Chapter 7- Policy Considerations. For the other states, outside of the current programs in California, carbon emissions will likely fall under federal policies. The current form of the CPP used to develop this IRP is not likely to remain in force under the current Federal Administration, but some form of regulation may replace it. The EPA sent information regarding CPP intent to the Office of Management and Budget on March 8, 2017, but had publically not released any proposal. This will require additional review and analysis in the next IRP. To consider
this future affect to our facilities, Montana reduces electric generation carbon emissions following existing CPP targets with new source complement, but the start of this effort is delayed four years. For the remaining western states, an emission reduction goal is in
place allowing each of the states to trade between each other based on the CPP target with new sources, but delayed until 2024. This IRP does not include specific carbon pricing except for states and provinces with existing carbon trading and tax regulations. By modeling emission goals and constraints, the model estimates potential emission trading prices for each ton of emissions. This methodology is in line with current policy discussions using cap and
trade markets rather than taxes or fees. Any future tax or price policy will require alternative analysis in a later IRP. Avista uses a different carbon reduction methodology in this IRP than in its prior plans. In this IRP, the model forces reductions in emissions
and the model estimates the shadow price of the emission reduction. Past IRPs used an arbitrary carbon price not tied to a specific reduction level. Arbitrary carbon prices without a correlation to market fundamentals may not achieve desired emissions reductions. Without a tie to external factors, a “tax or fee” may not achieve a specific emission goal due to changing external factors such as natural gas prices or hydroelectric conditions. For example, a higher carbon price is required to reduce
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 144 of 205
emissions when natural gas prices are high or hydroelectric conditions are unfavorable,
as such, a lower carbon price will reduce emissions in a low natural gas price environment or favorable hydroelectric conditions. This phenomenon is shown later in this chapter regarding the Washington Clean Air Rule. Avista will monitor policy
directives regarding greenhouse gas emissions to determine if the methodology is consistent with future policy objectives. Risk Analysis
A stochastic analysis, using the variables discussed earlier in this chapter, evaluates the market to account for future uncertainty. It is better to represent the electricity price forecast as a range because point estimates are unlikely to reflect underlying assumptions perfectly. Stochastic price forecasts develop more robust resource strategies by accounting for tail risk. The IRP uses 500 distinct 20-year market futures, providing a large distribution of the marketplace illustrating potential tail risk outcomes. The next several pages discuss the input variables driving market prices, and describe the methodology and the range in inputs used in the modeling process. Natural Gas Natural gas prices are a volatile commodity in relation to its historical prices. Daily Stanfield prices ranged between $1.21 and $24.36 per Dth between 2004 and 2017.
Figure 10.8 shows average Stanfield monthly prices since January 2004. Prices retreated from 2008 highs to a monthly price of $1.44 per Dth in March 2016. Prices since 2009 are lower than the previous five years, but continue to show volatility. Figure 10.8: Historical Stanfield Natural Gas Prices (2004-2015)

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 145 of 205
Figure 10.9 shows Stanfield natural gas price duration curves for 2018, 2025 and 2035.
The chart illustrates a larger price range in the later years of the study, reflecting less forecast certainty. Shorter-term prices are more certain due to additional market information and the quantity of near term natural gas trading. Figure 10.10 shows
another view of the forecast. The mean price in 2018 is $2.80 per Dth, represented by the horizontal bar, and the levelized price over the 20 years is $4.21 per Dth. The bottom and top of the bars represent the 10th and 90th percentiles. The bar length
indicates price uncertainty. Figure 10.11 illustrates the difference in pricing between the deterministic case and the mean and median of the 500 simulations. On a levelized basis, the median and deterministic cases are $4.00 and $4.03 per Dth, while the mean is higher at $4.20 per Dth2. Due to the methodology of the stochastic model, the mean
is greater than both the median and the starting deterministic. The model randomizes prices based on the lognormal distribution of the change in the deterministic monthly price forecast. Given a lognormal distribution, the mean prices trend higher than the
median prices given the skewed distribution curve. Figure 10.9: Stanfield Annual Average Natural Gas Price Distribution

2 The 20-year levelized mean price at Henry Hub is $4.35 per dekatherm.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 146 of 205
Figure 10.10: Stanfield Natural Gas Distributions
Figure 10.11: Stanfield Natural Gas Annual Price Statistical Comparison

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 147 of 205
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 data from 2007 to 2015 for the Western Interconnect as the basis for its analysis. Correlations 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 excursions witnessed by the electricity grid. The additional accuracy from modeling loads this way is crucial for understanding wholesale
electricity market price variation. It is vital for understanding the value of peaking resources and their use in meeting system variation.
Tables 10.5 and 10.6 present load correlations for the 2017 IRP. Statistics are relative to the Northwest load area (Oregon, Washington and Idaho). “NotSig” indicates no statistically valid correlation existed in the data. “Mix” indicates the relationship was not consistent across the 2007 to 2015 period. For regions and periods with NotSig and Mix results, the IRP does not model correlations between the regions. Tables 10.7 and 10.8 provide the coefficient of determination values by zone.3 Table 10.5: January through June Load Area Correlations
Area Jan Feb Mar Apr May Jun
Alberta Mix Mix Mix Mix Not Sig 20% Arizona 32% 38% Mix Not Sig Mix Not Sig
Avista 88% 86% 78% 77% 41% 79% British Columbia 86% 88% 72% 73% 41% 61% California Not Sig Not Sig Mix Mix 17% Not Sig
CO-UT-WY -23% Mix Mix -26% -3% -18% Montana 55% 65% 63% 52% Mix 46%
New Mexico 6% 6% Mix Mix Mix Mix North Nevada 58% 22% 6% Mix Mix 51% South Idaho 79% 76% 69% Mix Mix 49% South Nevada 52% 42% Mix Not Sig Mix 19%

3 The coefficient of determination is the standard deviation divided by the average.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 148 of 205
Table 10.6: July through December Load Area Correlations
Area Jul Aug Sep Oct Nov Dec Alberta 6% Not Sig Not Sig Not Sig 12% Mix
Arizona Mix Mix Mix -21% Mix 27% Avista 76% 78% 67% 79% 92% 92%
British Columbia 73% 56% 23% 75% 87% 83% California Not Sig Not Sig Not Sig -12% Mix Not Sig
CO-UT-WY -2% Mix -2% -12% 26% Mix Montana 6% 17% 6% 20% 79% 75%
New Mexico Not Sig Mix Mix Not Sig 34% 18% North Nevada 52% 53% 27% Mix 60% 34%
South Idaho 29% 38% 32% 6% 87% 84% South Nevada Mix 6% Mix -33% Mix 64%
Table 10.7: Area Load Coefficient of Determination (Standard Deviation/Mean)
Area Jan Feb Mar Apr May Jun
Alberta 4.9% 4.3% 4.8% 4.5% 4.9% 5.5% Arizona 8.2% 7.2% 7.2% 10.8% 15.1% 16.2% Avista 8.9% 8.5% 9.6% 8.7% 8.5% 10.3%
British Columbia 8.5% 7.9% 8.5% 8.0% 8.3% 8.6% California 9.3% 9.3% 9.4% 9.9% 11.4% 12.6%
CO-UT-WY 7.8% 7.7% 7.9% 7.5% 8.7% 13.2% Montana 7.8% 7.1% 7.7% 7.1% 7.3% 9.6% New Mexico 8.3% 8.4% 8.0% 9.5% 13.0% 13.6%
Northern Nevada 5.6% 5.6% 5.6% 6.4% 6.0% 9.4% Pacific Northwest 9.7% 9.2% 9.4% 8.7% 8.4% 8.9%
South Idaho 8.6% 8.2% 8.8% 9.8% 11.0% 14.9% South Nevada 6.5% 5.8% 6.3% 11.5% 17.1% 18.3% Table 10.8: Area Load Coefficient of Determination (Standard Deviation/Mean)
Area Jul Aug Sep Oct Nov Dec
Alberta 5.8% 5.5% 5.8% 4.6% 5.0% 4.8%
Arizona 14.0% 14.4% 15.6% 13.2% 7.5% 7.8% Avista 12.7% 12.4% 9.8% 8.8% 11.1% 9.9%
British Columbia 9.5% 9.4% 8.8% 8.9% 10.5% 9.2% California 13.1% 13.8% 14.6% 11.7% 9.9% 9.7% CO-UT-WY 12.8% 12.4% 11.4% 8.3% 8.6% 8.4%
Montana 9.8% 10.1% 8.1% 7.2% 8.6% 8.1% New Mexico 12.8% 12.5% 13.8% 10.8% 9.1% 8.8%
Northern Nevada 10.0% 9.3% 8.7% 5.9% 6.2% 6.5% Pacific Northwest 10.6% 10.5% 9.2% 9.0% 11.7% 10.9% South Idaho 11.4% 12.2% 12.8% 8.6% 10.6% 9.4%
South Nevada 15.7% 15.7% 17.8% 13.0% 6.8% 7.1%
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 149 of 205
Hydroelectric Variation
Hydroelectric generation is the most commonly modeled stochastic variable in the Northwest because historically it has a larger impact on regional electricity prices than other variables. The IRP uses an 80-year hydroelectric record starting with the 12-
month water year beginning October 1, 1928. Every iteration starts with a randomly drawn water year from the historical record, so each water year repeats approximately 125 times in the study (500 scenarios x 20 years / 80 water year records).
Wind Variation Wind has the most volatile short-term generation profile of any utility-scale resource. This makes it necessary to capture wind volatility in the power supply model to
determine the value of non-wind resources able to follow loads when wind production varies. Accurately modeling wind resources requires hourly and intra-hour generation shapes. For regional market modeling, the representation is similar to how AURORAXMP
models hydroelectric resources. A single wind generation shape represents all wind resources in each load area. This shape is smoother than an individual wind plant, but closely represents the diversity of a large number of wind farms located across a zone.
This simplified wind methodology works well for forecasting electricity prices across a large market, but does not accurately represent the volatility of specific wind resources Avista might select as part of its PRS. Therefore individual wind farm shapes form the basis of wind resource options for Avista. Fifteen potential 8,760-hour annual wind shapes represent each geographic region or
facility. Each year contains a wind shape drawn from these 15 representations. The IRP relies on two data sources for the wind shapes. The first is BPA balancing area wind data. The second is NREL-modeled data between 2004 and 2006.
Avista believes an accurate representation of a wind shape across the West requires data meeting several conditions:
1. Data correlated between areas using historical data.
2. Data within load areas is auto-correlated.4
3. The average and standard deviation of each load area’s wind capacity factor is consistent with the expected amount of energy for a particular area in the year and month.
4. The relationship between on- and off-peak wind energy is consistent with historic
wind conditions. For example, more energy in off-peak hours than on-peak hours where this has been experienced historically.
5. Hourly capacity factors for a diversified wind region are never greater than 90 percent due to turbine outages and wind diversity within the area.
Absent these conditions, it is unlikely any wind study provides a level of accuracy adequate for planning efforts. Avista’s methodology, first developed for its 2013 IRP,
4 Adjoining hours or groups of hours correlate to each other.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 150 of 205
attempts to meet the five conditions by first using a regression model based on historic
data for each region. The independent variables used in the analysis were month, night or day hour type, and generation levels from the prior two hours. To reflect correlation between regions, a capacity factor adjustment reflects historic regional correlation using
an assumed normal distribution with the historic correlation as the mean. After this adjustment, a capacity factor adjustment accounts for hours with generation levels exceeding a 90 percent capacity factor. Figure 10.12 shows a Northwest example of an
8,760-hour wind generation profile. This example, shown in blue, has a 31 percent capacity factor. Figure 10.13 shows actual 2016-wind generation recorded by BPA Transmission. The average wind fleet in BPA’s balancing authority had a 27.3 percent capacity factor in 2016. Figure 10.12: Wind Model Output for the Northwest Region
Forced Outages Most deterministic market modeling represents generator-forced outages with an average reduction to maximum capability. This over simplification represents expected values well; however, it is better to represent the system more accurately in stochastic modeling by randomly placing non-hydroelectric units out of service based on a mean time to repair and on an average forced outage rate. Internal studies show this level of modeling detail is necessary only for natural gas-fired, coal and nuclear plants with generating capacities in excess of 100 MW. Plants under 100 MW on forced outage do not materially affect market prices so their outages do not require stochastic modeling.
Forced outage rates and mean time to repair data for the larger units in the Western Interconnect come from analyzing the North American Electric Reliability Corporation’s Generating Availability Data System database, also known as GADS.

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 151 of 205
Figure 10.13: 2016 Actual Wind Output BPA Balancing Authority5
Market Price Forecast
An optimal resource portfolio cannot ignore the extrinsic value inherent in its resource choices. To determine extrinsic value, the 2017 IRP simulation compares each
resource’s expected hourly output using forecasted Mid-Columbia hourly prices over 500 iterations of Monte Carlo-style scenario analysis. Hourly zonal electricity prices are equal to either the operating cost of the marginal unit in the modeled zone or the economic cost to generate and move power from another zone to the modeled zone. A forecast of available future resources helps create an electricity market price projection. The IRP uses regional planning margins to set minimum capacity requirements rather than simply summing the capacity needs of
regional utilities. This reflects how some regions have resource surpluses even where individual utilities are deficit. This imbalance can be due in part to ownership of regional generation by independent power producers and possible differences in planning
methodologies used by utilities in the region. AURORAXMP assigns market values to each resource alternative available to Avista, but does not select Avista’s PRS. Several market price forecasts determine the value and volatility of a resource portfolio. As Avista does not know what will happen in the future, it relies on risk analysis to help determine an optimal resource strategy. Risk analysis uses several market price forecasts with different assumptions from the Expected Case
or with changes to the underlying statistics of a study. The modeling splits alternate cases into stochastic and deterministic studies.
5 Chart data is from the BPA at: http://transmission.bpa.gov/Business/Operations/Wind/default.aspx.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 152 of 205

A stochastic study uses Monte Carlo analysis to quantify the variability in future market prices, and the resultant impact on individual and portfolios of resources. These analyses include 500 iterations of varying natural gas prices, loads, hydroelectric
generation, thermal outages, and wind generation shapes. The IRP includes three stochastic studies—the Expected Case, a case with the social cost of carbon, and a benchmarking case excluding a cost of carbon. Mid-Columbia Price Forecast The Mid-Columbia market is Avista’s primary electricity trading hub. The market is historically the lowest cost in the west due to the amount of hydroelectric generation at
the hub and its proximity to Canadian gas supplies, though other markets can be less expensive at times when solar production is high and loads are low.
Fundamentals-based market analysis is critical to understanding the power industry environment. The Expected Case includes two studies. The first study is a deterministic market view using expected levels for the key assumptions discussed in the first part of
this chapter. The second is a risk or stochastic study with 500 unique scenarios based on different underlining assumptions for natural gas prices, load, wind generation, hydroelectric generation, forced outages, and inflation. Each study simulates the entire Western Interconnect hourly between 2018 and 2037. Figure 10.14 shows the Mid-Columbia stochastic market price results with horizontal bars representing the 10th and 90th percentile range for annual prices, diamonds show average prices, and arrows represent the 95th percentile. The 20-year nominal levelized price is $35.85 per MWh. Table 10.9 shows the annual averages of the stochastic case on-peak, off-peak and levelized prices. Spreads between on- and off-peak prices
average $5.09 per MWh over 20 years. The 2015 IRP annual average nominal price was $38.48 per MWh. The market price reduction from the 2015 study results from lower natural gas prices, lower loads, higher percentages of new lower-heat-rate natural
gas plants, and increased solar resources serving higher RPS requirements.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 153 of 205
Figure 10.14: Mid-Columbia Electric Price Forecast Range
Table 10.9: Annual Average Mid-Columbia Electric Prices ($/MWh)
Year Flat Off-Peak On-Peak
2018 23.79 19.48 27.02
2019 23.71 19.53 26.85
2020 23.99 20.16 26.85
2021 24.30 20.88 26.85
2022 25.95 22.59 28.47
2023 29.68 26.30 32.24
2024 32.03 28.90 34.38
2025 32.58 29.83 34.65
2026 34.27 31.77 36.13
2027 37.61 35.43 39.25
2028 40.18 38.28 41.60
2029 44.06 42.44 45.27
2030 46.86 45.15 48.15
2031 48.08 46.42 49.32
2032 51.10 49.17 52.55 2033 52.81 50.83 54.29 2034 55.09 53.07 56.61 2035 57.50 55.14 59.26 2036 60.52 58.24 62.22 2037 64.51 62.09 66.33 Levelized $35.85 $32.94 $38.03
$/MWh
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 154 of 205
Negative Electric Market Prices
The price forecast includes functionality to allow prices to go negative during oversupply events. In the past, oversupply events mostly occurred during spring periods when hydro was at high levels and wind was at full capacity. Traditionally these events occur
at night when loads are lower. Given increasing solar penetration, negative pricing is now occurring during the mid-afternoon. Avista models this by changing the supply curve of the hydro resources to a negative marginal price. Whenever demand is higher than hydro resources and must run generation, the marginal price is negative. Without this change, prices would never go below zero. This change properly values new resource opportunities such as storage and peaking units, but is also important to avoid overvaluing solar and other non-dispatchable resources during oversupply events. Greenhouse Gas Emission Levels Greenhouse gas levels are declining regionally and nationally as lower-cost natural gas
resources displace coal-fired generation, or even forces coal plants into early retirement. This IRP includes emissions limits and pricing as described earlier in this chapter. Figure 10.15 shows historic and expected greenhouse gas emissions for the
Western Interconnect. Greenhouse gas emissions from electricity generation decrease 6.2 percent between 2018 and 2037, and 2018 is 15 percent lower than 2015. The figure also includes 10th and 90th percentile statistics from the 500-iteration dataset. The higher and lower bands show emissions depending on changes in hydroelectric generation, load, resource availability and other factors. Lower load forecasts, lower natural gas prices, higher RPS requirements, coal-fired generation retirements and carbon limits drive the reductions. Once the majority of planned coal-fired plant retirements occur by 2032, emissions rise again reflecting new load met by a mixture of renewables and natural gas without coal retirements beyond current announcements. Figure 10.15: Western States Greenhouse Gas Emissions

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 155 of 205
Figure 10.16 illustrates the Expected Case emissions intensity for the Western
Interconnect. The CPP included an option for states to meet intensity goals for covered plants; this chart illustrates the reductions across the west to get a second look at the effectiveness of the emission constraints modeled. Between 2018 and 2037, the
emission intensity falls 17.5 percent. Alternatively, Figure 10.17 illustrates the change in emission intensity from 2018 to 2037 by area. All areas show declining emissions intensity with the exception of southern Idaho. The Idaho area has few emitting
resources (the region currently imports much of its baseload power) and the added natural gas increases its intensity. This chart shows the relationship of the emissions
intensity of facilities in the area compared to the area’s load. For example, Wyoming exports energy as its production is greater than its local load. Figure 10.16: Emission Intensity Metric

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 156 of 205
Figure 10.17: Instate Emission Intensity Change from 2018 to 2037
Resource Dispatch State-level RPS goals and greenhouse gas regulations change resource dispatch decisions and affect future power prices. The Northwest is witnessing the market-changing effects of more than 7,750 MW of wind. Figure 10.18 illustrates how natural
gas will increase as a percentage of Western Interconnect generation from 29 percent in 2018 to 37 percent 2037. The increase offsets coal-fired generation, with coal dropping from 23 percent in 2018 to 13 percent in 2037. Utility-owned solar and wind
generation increase from 11 percent in 2018 to 20 percent by 2037. New renewable generation also reduce coal-fired generation, but natural gas-fired generation is the primary resource meeting load growth due to economic dispatch and its addition to serve peak load growth. Figure 10.19, illustrates the resources meeting the reduction of coal and nuclear resources, and the increase in load. Natural gas meets 50 percent, while renewables meet the rest. Figure 10.18: Base Case Western Interconnect Resource Mix

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 157 of 205
Figure 10.19: Western Interconnect Resource Mix Changes
Greenhouse Gas Emission Pricing This IRP assumes the market will have emission caps; with this assumption, the
AURORAXMP model produces emission prices rather than a direct input as past IRPs. With this new constraint, the model produces a shadow price or hurdle rate for the plants with emission constraints. The resulting shadow prices as shown in Figure 10.20
affect the dispatch of plants in each area with reduction goals similar to models with a
carbon “price”. For Washington, the prices are near zero (depending on water year) until the early 2020s and remain below $5 per metric ton until 2030. These prices are a result
of increasing renewables on the system and the type of regulations in place. Avista’s facilities are not subject to these prices. The Washington projected emissions prices are lower than the prices required in coal regions as it is affecting natural gas resources rather than coal facilities. Natural gas prices need a lower financial disincentive to dispatch compared to coal as natural gas is on the margin most hours, while coal facilities are not.
In Washington, the emission policy only those plants identified by the Department of Ecology for the Clean Air Rule have constraints; therefore, the model may find cheaper ways to serve customers by running regulated plants only to the point of the regulation,
or importing power. The prices shown are for the average price. Prices can be significantly higher, as shown in Figure 10.21 from the stochastic analysis. If hydroelectric production is low and there are few alternatives to serve load, then emissions prices could be significantly higher. Further analysis is required due to the baseline emissions were not yet available at the time of the analysis. The AURORAXMP model is not able to produce prices based on a three-year compliance period; these prices assume a one-year compliance period. These prices do not represent the cost of compliance of this rule, but rather the implied cost for the electric sector to comply with the rule on a marginal basis. Non-electric participants subject to the rule could affect pricing if a future allowance market creates competition for scarce compliance options
or where by building additional renewables driving down wholesale prices.
Natural Gas53%
Hydro2%
Solar30%
Wind15%
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 158 of 205
Prices in Oregon are important to Avista, as our Coyote Springs 2 is located there. At
the time of the IRP analysis, Oregon had not identified a specific greenhouse gas policy. This IRP uses a 30 percent reduction goal from 2015 emissions by 2025. This amount is 10 percent lower than the Clean Power Plan new source complement mass based
goal. The resulting prices of this assumption are similar to the Washington results, as the states have similar generation profiles after existing coal-fired facilities retire. In this state, the average prices increase to approximately $11 per metric ton by 2037. The
resulting Montana prices are significantly higher than the coastal states, as emissions reductions must come from low marginal cost coal. The average price starts at $6.40 per metric ton in 2024 and escalates to $27 per ton in 2037.6 Coal facilities have lower base dispatch costs and require a high price to reduce dispatch. These results illustrate
the importance of policy making regarding emission reductions. For Avista, Colstrip is subject to this price adder for this analysis. This analysis illustrates how placing emission caps on individual states may drive in-state emissions lower, but will likely
cause increasing imports (or decreasing exports). The analysis also shows lowering emissions from coal facilities requires higher pricing than areas with natural gas. For the northwest, a carbon pricing mechanism would be more effective and less burdensome
on customers if it focused on coal rather than all resource types. Figure 10.20: Northwest Greenhouse Gas Emission Shadow Prices

6 At the 95th percentile, the 2024 price is $17 per metric ton and $60 per metric ton in 2037.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 159 of 205
Figure 10.21: Washington Clean Air Rule Pricing

Scenario Analysis
Scenario analysis evaluates the impact of changes in underlying market assumptions,
Avista’s generation portfolio, and new generation resource values. In addition to the Expected Case, this IRP includes two stochastic analyses. The first scenario is the case
where Colstrip retires and the second scenario reduces dispatch at Colstrip to 50 percent of current levels. Both scenarios are required due to the nature of the portfolio studies they support (as described in Chapter 11).
In past IRPs, several stochastic scenarios reviewed impacts on changes in environmental policy. These scenarios are important to consider for resource planning,
but given uncertainty in policy, limited time for the analysis, and only minor changes from the 2015 IRP, these additional scenarios are only indicative until greenhouse gas policy becomes more certain. Therefore, most of the IRP scenarios focus on Avista’s portfolio rather than the market. Per the TAC’s request, a deterministic market scenario simulates how the energy market would change if total emissions decreased 50 percent by 2035. This is a market scenario only, and not part of the portfolio analysis. It is
informative on the steps Avista’s portfolio would need to take to achieve this goal.
No Colstrip Scenario The No Colstrip Scenario models the implications of retiring Colstrip Units 3 & 4 early. The scenario values new resource options and the remaining portfolio in a marketplace without Colstrip. In addition, this scenario provides data about the regional financial impacts of a Colstrip closure, rather than just the impact to Avista from divestment of its share. This scenario assumes 1,000 MW CCCT, 430 MW peakers, and 300 MW wind replace the units. It does not attempt to represent the feasibility of this assumption, but rather helps understand the impacts to the overall market place. To simulate all the portfolio scenarios implications, this market scenario assumes Colstrip retires by the
end of 2023.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 160 of 205
Without Colstrip, regional market prices increase slightly as shown in Figure 10.22.
There are small differences beginning in 2024 with a $0.93 per MWh annual average price difference, overall prices are 2.7 percent higher without Colstrip. While these price changes are not large, it assumes the average price over a year in average water
conditions. At times, the price impacts are much greater and without replacement capacity, price impacts and reliability concerns increase. Beginning in 2024, the annual production costs to all western customers’ increases by $143 million with the closure of
Colstrip, plus the capital recovery of the additional new resources to replace the capacity estimated to be $250 million (2023 dollars). Without Colstrip, greenhouse gas emissions decrease; in 2030 model emissions were 3.0 percent lower, or nearly 6 million metric tons per year, as shown in Figure 10.23. Figure 10.22: Annual Mid-Columbia Flat Price Forecast Colstrip Retires Scenario
Colstrip Dispatch Reduction Scenario One of the methods to reduce emissions in the Northwest without closing Colstrip is to reduce its generation. This scenario shows the market implications if Colstrip dispatches
less to meet policy objectives. Because the plants are not retired, the scenario does not require replacement of the generation capacity. Emissions at the plant decrease beginning in 2023 and continue until the reduction reaches 50 percent of its typical generation amount. This dispatch constraint lowers emissions and creates an emission price for the two units. Figure 10.24 provides the resulting emission prices and emission quantities. Colstrip emissions fall by up to 4 million metric tons annually by 2037. This is approximately two-thirds of the emission reduction achieved by the Colstrip retires
scenarios. The emission price for this scenario starts around $7 per metric ton and escalates to $38 per metric ton by 2037. The prices shown are the mean of the 500 simulations. The 95th percentile price in 2037 is $75 per metric ton. Prices will vary
depending on the level of hydro production among other factors such as load, wind production and natural gas prices.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 161 of 205
Figure 10.23: No Colstrip Scenario Annual Western U.S. Greenhouse Gas Emissions

Mid-Columbia pricing in this scenario is nearly identical to the Expected Case because the marginal units driving prices do not change. With similar prices, total Western Interconnect emissions fall by one percent by 2035 or 2.3 million tons as the reduction
in Colstrip operations is offset by increases in natural gas dispatch in other regions. Figure 10.24: Colstrip Emissions & Pricing

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 162 of 205
Western Interconnect is 50 Percent Below 1990 Greenhouse Gas Levels Scenario
In each IRP, Avista studies different fundamental shifts in the electric market to understand the impacts to the market place. Past studies included high solar penetration, the impact of electric vehicles, and high carbon prices. This IRP uses the
new AURORAXMP constraint modeling functionality to develop a scenario that reduces Western Interconnect emissions by 50 percent compared to 1990 emission levels. Due to the uncertainty regarding regional conservation, load growth is the same as the Expected Case. This is a deterministic case similar to the Expected Case’s deterministic study. This scenario does not consider variability to hydro, natural gas prices, or other inputs as described earlier in the chapter. Figure 10.25 illustrates the change in greenhouse gas emissions compared to the Expected Case. Emissions in the scenario
start out lower due to changes in the new resource selection by the model because it anticipates significant future emission limits, so the model acquires renewables earlier.
Mid-Columbia prices are significantly higher in this scenario as significant emission prices drive emissions lower. Prices begin to deviate in 2029 when the price of carbon escalates at a higher rate, see Figure 10.26. Electric prices levelized for 20 years are 12
percent higher than the Expected Case, but 30 to 40 percent higher in the latter half of the study. See Figure 10.26. Carbon pricing shown below are for the entire Western Interconnect, as if the region was a cap and trade system. The levelized price for emission is $37.54 per metric ton between 2025 and 2037. This aggressive reduction goal requires new renewables and more natural gas-fired generation. Figure 10.27 illustrates the change in production in 2037 between this scenario and the Expected Case. Natural gas generation increases 20 percent, solar 40 percent, and coal reduces 86 percent. Wind generation remains flat, as solar is a lower cost alternative with fewer limitations. New investment in renewables drives total annual
cost to the system $15.3 billion higher than the Expected Case in the last 10 years of the study.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 163 of 205
Figure 10.25: Greenhouse Gas Reduction
Figure 10.26: Mid-Columbia Electric Price Comparison

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 164 of 205
Figure 10.27: 2037 Generation Mix Comparison

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 165 of 205
11. Preferred Resource Strategy
Introduction
This chapter describes potential costs and financial risks of Avista’s new resource and conservation strategy to meet future requirements over the next 20 years. It explains the decision making process used to select the Preferred Resource Strategy (PRS), and the resulting avoided costs used to set targets for future conservation acquisitions and new resource alternatives. The 2017 PRS describes a reasonable low-cost plan along the Efficient Frontier of potential resource portfolios accounting for fuel supply, regulatory and price risks. Major changes from the 2015 IRP include less energy efficiency (due to lower projected loads), the addition of demand response and storage resources, less natural gas-fired peaking
capacity, and replacing the planned 2026 CCCT with natural gas-fired peakers. Demand response returns to the PRS, as program options are more competitive
compared to building new resources. Storage appears for the first time in the plan as projected costs decline and its modular sizing fits Avista’s small load growth needs. Avista is also in the process of acquiring a 15 MW DC solar facility to sell to subscribing commercial and industrial customers of the Solar Select program (see Chapter 4 for further information). Due to a recent contract extension, Avista’s first resource deficit is in the winter of 2026 after the expiration of the Lancaster PPA.
Avista will meet the Washington Energy Independence Act with current resources through the duration of the plan and Avista anticipates reduction in greenhouse gas emissions at its owned facilities given current policy direction at the state level.

Supply-Side Resource Acquisitions
As shown in Figure 11.1, Avista has made several generation acquisitions and upgrades over the last 15 years, including:
 25 MW Boulder Park natural gas-fired reciprocating engines (2002);
 7 MW Kettle Falls natural gas-fired CT (2002);
Section Highlights
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 166 of 205
 35 MW power purchase agreement with the Stateline Wind Project (2004 – 2014);
 72 MW (total) hydroelectric upgrades (2007 – 2016);
 270 MW natural gas-fired Lancaster Generation Station tolling agreement (2010 – 2026);
 105 MW Palouse Wind power purchase agreement (2012 – 2042); and
 423 kW Boulder Park Community Solar (2015) Figure 11.1: Resource Acquisition History
Resource Deficiencies Avista uses both single-hour and 18-hour peak events (six hours per day spread over three consecutive days) to measure its projected resource adequacy. The single-hour event assures the system has enough machine capacity to meet an extreme load and/or outage event. The 18-hour methodology assures energy-limited hydroelectric resources
can meet multiday extreme weather events. For this plan, both summer and winter deficits are slightly higher for the single-hour event than the 18-hour event.
Avista’s peak planning methodology includes operating reserves, regulation, load following, variable generation (solar and wind) integration, and a planning margin. Avista currently projects having adequate resources between owned and controlled generation to meet physical energy and capacity needs until the end of 2026 when the Lancaster power purchase agreement expires.1 See Figure 11.2 for Avista’s physical resource positions for annual energy, summer capacity, and winter capacity. This figure accounts
1 Chapter 6 – Long-Term Position contains details about Avista’s peak planning methodology.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 167 of 205
for the effects of energy efficiency programs on the load forecast. Absent energy
efficiency, Avista would be deficient earlier. Figure 11.2: Physical Resource Positions (Includes Energy Efficiency)
Renewable Portfolio Standards The Washington Energy Independence Act (EIA) requires utilities with over 25,000 customers to meet 9 percent of current retail load from qualified renewable resources and 15 percent by 2020. The initiative also requires utilities to acquire all cost-effective energy efficiency. Avista expects to meet or exceed its EIA renewable energy requirements through the 20-year plan with a combination of qualifying hydroelectric upgrades, the Palouse Wind project, and the Kettle Falls Generating Station. Table 11.1 provides a list of the qualifying generation projects and associated generation and qualifying renewable energy credits
(RECs). Figure 11.3 shows the REC position forecast. The flexibility within the EIA to use RECs from the current year, from the previous year, or from the following year for compliance, mitigates year-to-year variability in the output of qualifying renewable
resources.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 168 of 205
Table 11.1: Qualifying Washington EIA Resources2
Kettle Falls GS Biomass 1983 47 374,824 355,607 Long Lake 3 Hydro 1999 4.5 14,197 14,197
Little Falls 4 Hydro 2001 4.5 4,862 4,862 Cabinet Gorge 3 Hydro 2001 17 45,808 45,808
Cabinet Gorge 2 Hydro 2004 17 29,008 29,008 Cabinet Gorge 4 Hydro 2007 9 20,517 20,517
Wanapum Hydro 2008 0 22,206 0 Noxon Rapids 1 Hydro 2009 7 21,435 21,435
Noxon Rapids 2 Hydro 2010 7 7,709 7,709 Noxon Rapids 3 Hydro 2011 7 14,529 14,529
Noxon Rapids 4 Hydro 2012 7 12,024 12,024 Palouse Wind Wind 2012 105 349,726 419,671
Nine Mile 1 & 2 Hydro 2016 4 21,950 21,950
Figure 11.3: REC Requirements versus Qualifying RECs for EIA

2 The forecasted REC’s shown are based on project capability and may differ from the EIA report due to the EIA report may include economic dispatch. Palouse Wind receives a 20 percent bonus apprenticeship
credit increasing the number of RECs. Wanapum has no qualifying RECs until the projects uses WREGIS.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 169 of 205
Resource Selection Process
Avista uses several decision support systems to develop its resource strategy, including AURORAXMP and Avista’s PRiSM model. The AURORAXMP model, discussed in detail in the Market Analysis chapter, calculates the operating margin (value) of every resource
option considered in each of the 500 Monte Carlo simulations of the Expected Case, as
well as Avista’s existing generation portfolio. The PRiSM model helps make resource decisions. Its objective is to meet resource deficits while accounting for overall cost, risk,
capacity, energy, renewable energy requirements, and other constraints. PRiSM evaluates resource values by combining operating margins with capital and fixed operating costs. The model creates an Efficient Frontier of resources, or least-cost
portfolios, given a certain level of risk and constraints. Avista’s management selects a resource strategy using this Efficient Frontier to meet all capacity, energy, renewable energy, and other requirements.
PRiSM Avista staff developed the first version of PRiSM in 2002 to support resource decision
making in the 2003 IRP. Enhancements over the years have improved the model. PRiSM uses a mixed integer programming routine to support complex decision making with multiple objectives. These tools provide optimal values for variables, given system constraints. PRiSM Model Overview The PRiSM model requires a number of inputs:
1. Expected future deficiencies
o Greater of summer 1- or 18-hour capacity
o Greater of winter 1- or 18-hour capacity
o Annual energy
o EIA requirements 2. Costs to serve future retail loads as if served by the wholesale marketplace
3. Existing resource and conservation contributions
o Operating margins
o Fixed operating costs 4. Resource and conservation options
o Fixed operating costs
o Return on capital
o Interest expense
o Taxes
o Generation levels
o Emission levels
5. Constraints
o Must meet energy, capacity and RPS shortfalls without market reliance
o Resources quantities available to meet future deficits PRiSM uses these inputs to develop an optimal resource mix over time at varying levels of risk. PRiSM considers new resource costs over the next 50 years to consider long-term
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 170 of 205
resource implications, but it weights the first 25 years more than the later years to highlight
the importance of nearer-term decisions. Equation 11.1 shows a simplified view of the PRiSM linear programming objective function. Equation 11.1: PRiSM Objective Function Minimize: (X1 * NPV2018-2042) + (X2 * NPV2018-2067) Where: X1 = Weight of net costs over the first 25 years (95 percent) X2 = Weight of net costs over the next 50 years (5 percent) NPV is the net present value of total system cost.3
An efficient frontier captures the optimal resource mix graphically given varying levels of cost and risk. Figure 11.4 illustrates the efficient frontier concept.
Figure 11.4: Conceptual Efficient Frontier Curve
As you attempt to lower risk, costs increase. The optimal point on the Efficient Frontier depends on the level of acceptable risk. No best point on the curve exists, but Avista prefers points where small incremental cost additions offer larger risk reductions. Portfolios to the left of the curve are more desirable, but do not meet the planning requirements or resource constraints. Examples of these constraints include environmental costs, regulation, and the availability of commercially viable technologies. Portfolios to the right of the curve are less efficient as they have higher costs than a
3 Total system cost is the existing resource marginal costs, all future resource fixed and variable costs, and all future energy efficiency costs, and the net short-term market sales/purchases.

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 171 of 205
portfolio with the same level of risk. PRiSM meets all deficit projections with new
resources of the actual sizes available in the marketplace and does not use market purchases. As discussed earlier in this chapter, reflecting real-world constraints in the model is necessary to create a realistic representation of the future. Some constraints are
physical and others are policy driven. The major resource constraints are capacity and energy needs, the EIA, and the greenhouse gas emissions performance standard. Preferred Resource Strategy
The 2017 PRS consists of existing thermal resource upgrades, energy efficiency, demand response, storage and natural gas-fired peakers (See Table 11.2 and Figure 11.5). The 15 MW (DC) solar facility for Avista’s new voluntary Solar Select Program is also included in the resource plan4. Prior to the first capacity and energy need in 2026, the PRS shows Avista beginning two demand response programs to reduce loads at system peak. Both Solar Select and the DR programs will require commercial and industrial cooperation,
regulatory approvals, permitting, and starting the program early to ensure enough participants are available when our deficit requires it.
Additional thermal based resources meet the first large deficit created by the expiration of the Lancaster PPA. It is possible this resource could be re-acquired, or an alternative market resource may be available at a lower cost. Without an acquisition, the first new resource is a 192 MW of natural gas-fired peakers and upgrades at existing thermal facilities. Given the small cost differences between the evaluated natural gas-fired peaker technologies, the future technology decision likely will be refined in a Request for Proposals (RFP) process. Technological changes in efficiency and flexibility may lead Avista to revisit this resource choice closer to the actual need. Table 11.2: 2017 Preferred Resource Strategy
Resource By the End of Year ISO Conditions (MW) Winter Peak (MW) Energy (aMW)
Solar (Solar Select Program) 2018 15 0 3
Natural Gas Peaker 2026 192 204 178
Thermal Upgrades 2026-2029 34 34 31 Storage 2029 5 5 -0 Natural Gas Peaker 2030 96 102 89 Natural Gas Peaker 2034 47 47 43 Total 389 392 344
Efficiency Improvements Acquisition Range Winter Peak Reduction (MW)
Energy (aMW)
Energy Efficiency 2018-2037 203 108
Demand Response 2025-2037 44 <0
Distribution Efficiencies <1 <1 Total 247 108
4 The size of the Solar Select facility may change from the RFP amount if program participation exceeds
the initial 15 MW program.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 172 of 205
Figure 11.5: New Resources to Meet Winter Peak Loads
After a combination of upgrades to existing thermal facilities, new peakers, and demand response, Avista’s customers still will require additional capacity as loads grow and
contracts expire. The next acquisition is a storage resource. The selected storage unit has a five-megawatt capacity rating, and 15 megawatt-hours of storage. Following the storage resource addition, a significant wholesale power contract expires at the end of
2030. To fill this gap, PRiSM selects a 96 MW natural gas fired peaker unless renewing the contract under favorable terms benefits customers. The last selected resource of the 20-year plan is a 47 MW natural gas-fired peaker by the end of 2034. 2015 IRP Comparison The 2017 PRS differs from the 2015 PRS shown in Table 11.3. Lower load growth and contract changes push resource needs out to 2026 rather than by the end of 2020. New resource needs are 191 MW lower due to lower load growth, higher expected conservation at the time of system peak, and the addition of new demand response and storage programs. These factors further reduce the need for new fossil fuel resources.
The 2015 PRS combined cycle plant is now too large relative to the projected need for replacing Lancaster with a new facility. Further, market conditions are changing due the amount of new renewable resources in the west, favoring flexible peaking resources over
historically intermediate and baseload resources. Avista preformed a scenario, discussed in Chapter 12, showing if Avista continued assuming replacing Lancaster with a new CCCT plant to see the cost and risk impact to the portfolio.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 173 of 205
Table 11.3: 2015 Preferred Resource Strategy
Resource By the End of Year ISO Conditions (MW) Winter Peak (MW) Energy (aMW)
Natural Gas Peaker 2020 96 102 89
Thermal Upgrades 2021-2025 38 38 35
Combined Cycle CT 2026 286 306 265
Natural Gas Peaker 2027 96 102 89 Thermal Upgrades 2033 3 3 3 Natural Gas Peaker 2034 47 47 43 Total 565 597 524
Efficiency Improvements Acquisition Range Winter Peak Reduction (MW)
Energy (aMW)
Energy Efficiency5 2016-2035 193 132
Distribution Efficiencies <1 <1 Total 193 132
Energy Efficiency Energy efficiency is an integral part of the PRS. It also is a critical component of the EIA requirement for utilities to obtain all cost-effective conservation. PRiSM considers energy efficiency and supply side options at the same time to ensure compliance with the EIA.
PRiSM models each specific energy efficiency measure individually and does not bundle measures. This allows the selection of different conservation amounts at each point along the Efficient Frontier to capture changes in the risk profiles of additional conservation.
This capability improves previous IRP evaluations assuming a constant conservation acquisition level along the entire curve. Conservation options inclusion within PRiSM requires a load forecast without future conservation. Due to industry-standard load forecasting methods, Avista’s load forecast is the load expectation net of future energy efficiency. Estimating the amount of conservation included in the forecast requires evaluating its economic potential. This requires an iterative process with PRiSM to validate if selected conservation is similar to the assumed conservation level in the load forecast. For example, if PRiSM selects less conservation than originally estimated, it runs again with a lower amount of conservation
until the predetermined conservation is similar to the selected conservation on an annual energy basis. For this IRP, selected conservation is very similar to the levels in the forecast. The difference is three percent higher in the first 10 years, and two percent
higher over 20 years, or 1.9 aMW. Figure 11.6 illustrates the load forecast with and without conservation. The selected 108 aMW of savings represents 53.3 percent of expected load growth between 2018 and 2037. Please refer to Chapter 5 for a detailed discussion of energy efficiency resources.
5 Total energy efficiency estimates include savings from transmission and distribution system losses.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 174 of 205
Because portfolio analysis described in this chapter considers the impacts of transmission
and distribution losses, savings in Chapter 5 are lower than shown here. Figure 11.6: Load Forecast with and without Energy Efficiency
Grid Modernization Distribution feeder upgrades entered the PRS in the 2009 IRP and the grid modernization process began with the Ninth and Central feeder in Spokane. The decision to rebuild a feeder considers savings from reducing energy losses, operation and maintenance
savings, the age of installed equipment, reliability indices, and the number of customers on the feeder. System reliability, instead of energy savings, generally drives feeder rebuild decisions. Therefore, feeder upgrades are no longer included as a resource option in PRiSM. A broader discussion of Avista’s feeder rebuild program is in Chapter 8. Natural Gas-Fired Peakers Avista plans to locate potential sites for new natural gas-fired generation capacity within
its service territory ahead of an anticipated need. The option of having a utility-owned site is very low cost relative to the final acquisition cost of a natural gas-fired plant, and this strategy ensures customers will not pay a premium over the actual cost of building a new
asset. A 2013 Action Item was to identify a utility-build natural gas resource site. Since then, Avista procured land in North Idaho in the event a greenfield site benefits customers. A second option for a smaller resource need is possible at the Rathdrum CT site.
Avista is not specifying a preferred peaking plant technology at this time. Tradeoffs will occur between capital costs, size, operating efficiency, and flexibility. Relative to other natural gas-fired peaking facilities, frame CT machines are a lower capital-cost option, but have higher operating costs and less flexibility, while the hybrid technology and aero
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 175 of 205
turbines have higher capital costs, lower operating costs, and more operational flexibility.
Advances in natural gas-fired reciprocating engines are also of interest. These resources utilize a group of smaller units to reduce the risk of a larger single plant breaking down, have lower heat rates, and are highly flexible, but can be more capital and O&M intensive
than other technologies. Increased flexibility requirements and greenhouse gas emissions costs could make a hybrid plant or reciprocating engines preferable. Avista currently has enough resource flexibility to meet customer needs to drive the strategy
towards a lower cost peaker option, but potential future participation in an energy imbalance markets may provide enough revenues for a flexible peaker to offset the higher costs. It is also possible other resource options such as CCCT, storage, or hydro could cost effectively compete against new peakers when procuring the new resource. Greenhouse Gas Emissions Chapter 10 – Market Analysis, discusses how greenhouse gas emissions decrease due
to coal plant retirements across the Western Interconnect. Avista’s projected resource mix does not include any retirements. The only significant carbon emitting resource leaving the portfolio is the expiration of the Lancaster PPA in 2026. Figure 11.7 presents
Avista’s expected greenhouse gas emissions (excluding Kettle Falls GS) with the addition of 2017 PRS resources. The estimates in Figure 11.7 do not include emissions from purchased power or adjustments to reduce emissions for off-system sales. Emissions in 2037 are 11 percent lower than the 2018/19 average emissions and 18 percent lower on a per MWh basis. Emissions are 29 percent lower as compared to the 2015 IRP’s estimate for 2035. The emissions reduction comes from adding natural gas-fired peaking units instead of building a new CCCT facility, and a reduction in the dispatch at Colstrip 3 & 4 due to modeled emission regulations. Figure 11.7: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 176 of 205
Capital Spending Requirements
The IRP assumes Avista will finance and own all new resources for IRP planning purposes.6 A competitive acquisition processes may hold different result, but under this assumption, and the resources identified in the 2017 PRS, the first capital addition to rate
base is in 2025 as capital improvements are required for the stand-by generation DR program. In 2027, significant investment will be required for the first natural gas-fired peaker as a replacement for the Lancaster PPA. If a new facility replaces Lancaster, construction would begin prior to need, but the resource’s capital cost would not enter rate base until after it is placed in service. The capital cash flows in Table 11.4 include AFUDC, generation capital costs, and transmission investments for generation, tax incentives, and sales taxes. Over the 20-year IRP timeframe, $538 million (nominal) in generation and related transmission expenditure is required to support the PRS. Table 11.4: PRS Rate Base Additions from Capital Expenditures (Millions of Dollars)
Year Investment Year Investment 2018 0.0 2028 2.1
2019 0.0 2029 9.5 2020 0.0 2030 9.9
2021 0.0 2031 140.1 2022 0.0 2032 0.5
2023 0.0 2033 0.5 2024 0.0 2034 0.5
2025 2.3 2035 94.1 2026 2.0 2036 0.5
2027 275.7 2037 0.5 2018-27 Total 280.0 2028-37 Totals 258.2
Annual Power Supply Expenses and Volatility PRS variance analysis tracks fuel, variable O&M, emissions, and market transaction
costs for the existing resource portfolio for each of the 500 Monte Carlo iterations of the Expected Case risk analysis. In addition to existing portfolio costs, new resource capital, fuel, O&M, emissions, and other costs provide a range of expected costs to serve future loads. Figure 11.8 shows expected PRS costs through 2037 as the blue bars. In 2018, portfolio costs average $26 per MWh. By 2037, costs approach $60 per MWh. The chart shows a two-sigma cost range with yellow diamonds representing the lower range and orange triangles representing the upper range. The main drivers increasing power supply
costs and volatility are natural gas prices and weather, which affect both hydroelectric generation and load variability. Avista increases the volatility assumption of future natural gas prices because the commodity price has unknown future risks and a history of
volatility.
6 Except for resources taking advantage of the ITC, such as solar.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 177 of 205
Figure 11.8: Projected Power Supply Expense Range
Efficient Frontier Analysis
The Efficient Frontier analysis is the backbone of the PRS. The PRiSM model develops the efficient frontier by simulating the costs and risks of resource portfolios using a mixed-integer linear program. PRiSM finds an optimized least cost portfolio for a range of risk
levels. The PRS analyses examined the following portfolios.
 Least Cost: Meets all capacity, energy and RPS requirements with the least-cost resource options. This portfolio ignores power supply expense volatility in favor of
lowest-cost resources.
 Least Risk: Meets all capacity, energy, and RPS requirements with the least-risk
mix of resources. This portfolio ignores the overall cost of the selected portfolio in favor of minimizing year-on-year portfolio cost variability.
 Efficient Frontier: Meets all capacity, energy, and RPS requirements with sets of intermediate portfolios between the least risk and least cost options. Given the resource assumptions, no resource portfolio can be at a better cost and risk combination than these portfolios.
 Preferred Resource Strategy: Meets all capacity, energy, and RPS requirements while recognizing both the overall cost and risk inherent in the portfolio. Avista’s management chose this portfolio as the most reasonable strategy given current information.
Figure 11.9 presents the Efficient Frontier in the Expected Case. The x-axis is the levelized nominal cost per year for the power supply portfolio, including capital recovery,
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 178 of 205
operating costs, and fuel expense; the y-axis displays standard deviation of power supply
costs in 2030. It is necessary to move far enough into the future so load growth provides PRiSM the opportunity to make new resource decisions. The year 2030 is far enough into the future to account for the risk tradeoffs of several resource decisions. Using an earlier
year to measure risk would have too few new resource decisions available to distinguish between portfolios. Avista chose to use the least cost portfolio for this IRP. Past IRPs selected a portfolio with lower risk, but slightly higher cost. The main difference between this plan and prior plans is first the choice to replace Lancaster after the expiration of the PPA with peaking plants. Avista chose to move away from a baseload resource due to the lower capacity
requirements upon its expiration. With the lower capacity requirement, adding a CCCT (without a partner) would increase customer’s costs until the company could grow into the excess capacity. The second reason for the change is to take advantage of a low electric
market price forecast by selecting natural gas-fired peakers and demand response.
Avista’s resource strategy meets reliability requirements and selects new resources to meet rapid changes in daily price volatility due to renewable resources in the region. If
Avista maintains its strategy to replace Lancaster with a new CCCT, the costs would be 0.8 percent higher (PVRR) and the risk in 2030 would increase by 10 percent. While this scenario is similar to the portfolios on the Efficient Frontier analysis, there are other more optimal portfolios with similar risk, but at lower cost. More information regarding this scenario is in Chapter 12. Figure 11.9: Expected Case Efficient Frontier

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 179 of 205
Selecting the appropriate point on the Efficient Frontier is not solvable through a
mathematical formula. Portfolio selection along the Efficient Frontier is from a
determination of management’s judgment of cost versus risk. In prior IRPs, management selected lower heat rate facilities to protect the portfolio from wholesale market volatility
by moving down the frontier curve. In this IRP, management is pursuing a modestly higher risk strategy by selecting peakers over CCCTs. Given the uncertainties in the marketplace today, including carbon mitigation policies, this choice gives more flexibility. Since our
resource need is nine years away, multiple IRP’s will be able to change course if needed when more information becomes available. The 2015 IRP presented a method for reviewing portfolios along the Efficient Frontier as part of a request by the Washington Commission Staff. This method is a risk adjusted Present Value of Revenue Requirement, or PVRR, taking into account the tail risk. The first step calculates risk adjusted PVRR for each portfolio. This calculation is the net
present value (NPV) of the future revenue requirements, plus the present value of taking
each of the future year’s tail risk, calculated by five percent of the 95th percentile’s increase in costs. This methodology assumes the lowest NPV should yield the best
strategy. Figure 11.10 shows the results of this study on the Efficient Frontier. The first two portfolios are the least cost adjusted for this risk calculation. The second portfolio is 0.003 percent lower cost than the PRS (Least Cost scenario), meaning the portfolios are essentially identical. The only difference is the resources selected are after 2035. Figure 11.10: Risk Adjusted PVRR of Efficient Frontier Portfolios

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 180 of 205
To illustrate tradeoffs between the cost and risk of each portfolio along the Efficient
Frontier, a point-to-point derivative of the slope of the change in cost relative to the change in absolute costs is useful. In this case, a greater slope indicates increasing benefits for trading risk reduction for higher portfolio costs. Figure 11.11 illustrates the results of this
study. The PRS selected by PRiSM is the least cost portfolio, but moving down the frontier does provide good risk versus cost tradeoffs, as the slope of the Efficient Frontier is steeper until the sixth portfolio. As time passes, Avista may choose to move further down the Efficient Frontier given Avista’s first resource need is not eminent. Figure 11.11: Risk Adjusted PVRR of Efficient Frontier Portfolios
Other Efficient Frontier Portfolios In addition to the PRS, the Efficient Frontier contains 15 additional resource portfolios. The lower cost and higher risk portfolios contain primarily natural gas peakers and renewable resources to reduce risk. The amount of conservation varies in these portfolios as it lowers risk and fills deficiencies depending on the resources selected. For example, the model must select a resource size actually available in the marketplace. Given this
“lumpiness”, it may be more efficient to meet some needs with conservation rather than
building a much larger generation asset. This discussion continues in Chapter 12 – Portfolio Scenarios.
Table 11.5 details the selected resource totals between 2018 and 2037 for each Efficient Frontier portfolio. Toward the middle of the Efficient Frontier, PRiSM favors wind and solar to reduce market risk as additional conservation resources become more expensive. The lower half of the Efficient Frontier includes portfolios with large capacity surpluses and
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 181 of 205
renewable resources, meanwhile maxing out the amount of conservation included in the
model. The least risk portfolio has no financial objective and selects as many resources
as possible given the model’s constraints to lower risk. A new natural gas CCCT does not appear anywhere on the Efficient Frontier for the first time since PRiSM was adopted in
the 2003 IRP. This is because new CCCT units are too large relative to Avista’s load requirements. Table 11.5: Alternative Resource Strategies (2035) along the Efficient Frontier (MW)
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Determining the Avoided Costs of Energy Efficiency
The Efficient Frontier methodology determines the avoided cost of new resource additions included in the PRS. There are two avoided cost calculations for this IRP: one for energy efficiency and one for new generation resources. The energy efficiency avoided cost is
higher because it includes benefits beyond generation resource value. Avoided Cost of Energy Efficiency
Since PRiSM selects energy efficiency, the prior IRP method of calculating avoided costs is no longer required; but estimating these values is helpful in selecting future conservation measures for more detailed analysis between IRPs. The process used to
estimate avoided cost calculates the marginal cost of energy and capacity of the resources selected in the PRS. The energy value uses hourly energy prices to value more highly measures providing more contribution during system peak. The value of conservation measures includes the energy value, the ten percent Power Act adder and
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 182 of 205
the value of loss savings.7 Reducing customer loads saves future distribution and
transmission capital and O&M costs, and is included in the conservation-avoided cost calculation. The final component of avoided cost accounts for the savings from avoided new capacity. This capacity value is the difference between the cost of a resource mix
and the value the mix earns from energy sales in the wholesale marketplace. Equation 11.2 describes the avoided costs to evaluate conservation measures. This equation is the same as the 2015 IRP.
Equation 11.2: Conservation Avoided Costs {(E + (E * L) + DC) * (1 + P)} + PCR Where: E = Market energy price. The price calculated by AURORAXMP is $35.85 per MWh
assuming a flat load shape.
PCR = New resource capacity savings for the PRS selection point is estimated to be $120 per kW-year (winter savings only).
P = Power Act preference premium. This is the additional 10 percent premium given as a preference towards energy efficiency measures.
L = Transmission and distribution losses. This component is 6.0 percent based on
Avista’s estimated system average losses.
DC = Distribution capacity savings. This levelized value is approximately $34.41
per kW-Year.
Determining the Avoided Cost of New Generation Options
The 2017 IRP’s avoided costs are in Table 11.6. However, avoided costs will change as
Avista’s loads and resources change, as well with the wholesale power marketplace changes. The prices shown in the table represent energy & capacity values for different periods and product types. For example, for a new project with equal deliveries over the year in all hours has an energy value equal to the Flat Energy price shown in Table 11.6.
Traditional on-peak and off-peak pricing is also included as a comparison to the flat price. In addition to the energy prices, this theoretical resource would also receive the capacity value as it produces power at the time of system peak. This system peak contributing
value begins in 2027 for potential resources that can dependably meet winter peak requirements. Capacity values shown below are the marginal cost of the most expensive significant resource from the PRS each year. The significant resources in this case are the natural gas-fired peakers. These resources set the avoided capacity cost, rather than smaller technologies, as the smaller technologies selected may not represent the marginal cost
7 The Power Act adder refers to one aspect of federal law enacted in 1980 along with the creation of the
NPCC. The NPCC includes the 10 percent adder to deferred capacity, given Avista’s new conservation methodology using this 10 percent adder would not allow Avista’s PRiSM model to solve, as it would be non-linear. Avista compared it’s conservation method to the older method that calculates conservation outside PRiSM with the 10 percent adder in the 2015 IRP and both methods produced similar results.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 183 of 205
if changes are made to loads or resources or if the PRiSM model is able to select
resources to proper size requirement. The capacity payment applies to the capacity contribution of the resource at the time of the winter peak hour. To obtain a full capacity payment the resource must generate 100 percent of its capacity rating at the time of
system peak. Solar receives no payment because it does not generate at the time of
Avista’s planned system peak (winter evenings or mornings when it is still dark). Wind resources may qualify for some contribution depending on the correlation and
diversification of the resource. For example, this IRP assumes 7.5 percent winter capacity credit for Montana wind resources. The capacity cost methodology of this analysis is the same as the 2015 and prior plans by using the natural gas-fired resources as the avoided capacity unit. The only major difference from prior plans is the inclusion of specific avoided costs for renewables. As an alternative to showing tipping point analysis to determine when a solar or wind
resource is cost effective, the avoided energy value of these resources is part of this table. For solar, the levelized price to be economic for customers between 2017 and 2037, is $29.90 per MWh and for wind the economic price is $31.81 per MWh. These values do
not include costs to integrate variable energy production, reserves, or interconnection costs, but represent the energy value of the resource’s generation. The value attributed to these resources vary due to the time of expected delivery of the resources. Table 11.6: 2017 IRP Avoided Costs
Year Flat Energy $/MWh
On-Peak Energy $/MWh
Off-Peak Energy $/MWh
Capacity $/kW-Yr Example WA Solar $/MWh
Example WA Wind $/MWh
2018 23.79 27.02 19.48 0 23.70 21.66 2019 23.71 26.85 19.53 0 23.28 21.71 2020 23.99 26.85 20.16 0 22.37 21.76 2021 24.30 26.85 20.88 0 21.67 21.63 2022 25.95 28.47 22.59 0 22.54 22.92 2023 29.68 32.24 26.30 0 25.36 26.35
2024 32.03 34.38 28.90 0 26.62 28.40
2025 32.58 34.65 29.83 0 26.66 28.85
2026 34.27 36.13 31.77 0 27.42 30.23
2027 37.61 39.25 35.43 171 29.51 33.25
2028 40.18 41.60 38.28 174 30.91 35.20
2029 44.06 45.27 42.44 178 33.84 38.65
2030 46.86 48.15 45.15 181 36.19 41.01
2031 48.08 49.32 46.42 185 36.88 41.98
2032 51.10 52.55 49.17 189 39.26 44.82
2033 52.81 54.29 50.83 192 40.73 46.13
2034 55.09 56.61 53.07 196 43.28 48.35
2035 57.50 59.26 55.14 200 45.96 50.51
2036 60.52 62.22 58.24 204 48.13 53.15
2037 64.51 66.33 62.09 208 51.98 57.14

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 184 of 205

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 185 of 205
12. Portfolio Scenarios
Introduction
The Preferred Resource Strategy (PRS) is Avista’s 20-year strategy to meet future loads. Because the future is often different from the IRP forecast, the strategy needs to be flexible enough to benefit customers under a range of plausible outcomes. This chapter investigates the cost and risk impacts to the PRS with different futures the utility might face. It reviews the impacts of losing a major generating unit, evaluates alternative loads, determines the impact of unit sizing, and the selection of portfolios to the right of the Efficient Frontier. All portfolios include the Solar Select project discussed in Chapter 11.
Load Forecast Scenarios The PRS meets the Expected Case’s load growth of 0.45 percent and winter peak growth of 0.39 percent over the next 20 years. Chapter 3 – Economic and Load Forecast provides details about the alternative load forecasts and Table 12.1 summarizes the alternative growth assumptions used to determine how the plan would change under different
economic conditions. Table 12.1: Load Forecast Scenarios (2018-2037)
Scenario Energy Growth (%) Winter Peak Growth (%)
Summer Peak Growth (%)
Expected Case 0.45 0.39 0.42
High Load 0.74 0.72 0.78
Low Load 0.16 0.03 0.04

Table 12.2 shows the changes to the PRS for each load growth scenario. In each scenario, a natural gas-fired CT is required by the end of 2026. Both the Low Load Growth case and the PRS add a 192 MW natural gas-fired CT by the end of 2026. The High Load Growth case requires 288 MW of additional capacity by the end of 2026. In all cases, the thermal upgrade selection is the same, but the timing of resources change, as the resource needs change. In both alternative scenarios, the storage facility is not cost effective, due to the size of selected resources needed to meet capacity needs. In the Expected Case, storage is the lowest cost resource for small incremental needs, but not for larger requirements. The portfolios for all three cases are similar with no scenario
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 186 of 205
requiring a different decision date for a new facility; the only major difference is the size
of the addition. Near the 2026 requirement, Avista will have a greater understanding of its actual requirements. Table 12.2: Resource Selection for Load Forecast Scenarios
Resource Expected Case's PRS
High Load Growth
Low Load Growth
NG Peaker 335 477 192
NG Combined Cycle CT 0 0 0
Wind 0 0 0
Solar 0 0 0
Demand Response 49 49 49
Storage 5 0 0 Thermal Upgrades 34 34 34 Hydro Upgrades 0 0 0 Total 423 560 275
Colstrip Scenarios
Coal-fired power plants are facing pressure from both policy requirements and economics to reduce their dispatch or to shut down. Avista’s TAC and state commissions asked Avista to study the impacts of shuttering Colstrip prior to the end of its operating life. This IRP studies two alternative shutdown scenarios including coal-fired plant dispatch is limited due to more restrictive carbon reduction policies relative to the Expected Case’s assumption. In the Expected Case, Avista’s ownership interests in the plant remains cost effective for the next 20 years, although it dispatches less due to carbon regulation projections. The Expected Case also includes Selective Catalytic Reduction (SCR) beginning service in
2028, significant capital expenses for Coal Combustion Residual (CCR) requirements and water management issues. Operating costs will increase when Units 1 & 2 close because there will be additional O&M costs and possible requirements for additional mercury
controls. Colstrip Retirement Scenario This IRP includes two scenarios with Colstrip retiring in 2030 and 2035. Both represent plausible early retirement dates when the plant could end service to customers. These scenarios assume both closure dates eliminate capital spending for the SCR and shorten capital recovery to current and future capital to five years after the retirement date. Future capital costs are lower than the Expected Case as certain capital improvements are cancelled. The CCR costs remain the same as in the Expected Case, but the time to complete the projects accelerates. The scenarios do not include costs related to
employee retraining or relocation, payments to other owners, or decommissioning beyond those already included rates.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 187 of 205
Table 12.3 shows the resource strategy for the Colstrip retirement scenarios. For the 2030
scenario, the table includes options for natural gas peakers and a CCCT. The 2035 scenario only shows replacement with peakers, although a CCCT could replace the plant, the cost illustration shown in 2030 represents this scenario. Figure 12.1 illustrates the
costs and power supply risks of retiring Colstrip compared to the Efficient Frontier and the PRS. This chart shows the annual levelized costs between 2018 and 2042 on the x-axis and the 2037 standard deviation of power supply costs on the y-axis1. A separate scenario replacing Colstrip with energy storage and renewables appears later in this chapter. Retiring Colstrip early increases costs compared to the PRS, while pushing the retirement date out to 2035 is the least cost of the retirement scenarios, due to the added costs representing a smaller portion of the financial period. To understand the cost increases
in the year of retirement, Figure 12.2 compares the annual cost of each scenario and the PRS.
The year following the plant retirement, power supply costs increase $50 to $60 million due to the cost of new capacity; this represents a 10 to 13 percent increase in power supply expenses as compared to the PRS. Reduced capital spending offsets some of the
cost increases prior to the shutdown, but not enough to offset the increase. The CCCT option costs $1.8 million more per year (0.4 percent than the peaker option, but risk is 8 percent lower. Table 12.3: Colstrip Retires- Resource Strategy Options (ISO Conditions MW)
Resource By End of Year
2030 Retirement with Peaker
2030 Retirement with CCCT
2035 Retirement with Peaker
Natural Gas Peaker 2026 192 192 192
Thermal Upgrades 2027-2030 34 34 34
Storage 2028 5 5 5
Natural Gas Peaker 2030 288 0 96
Natural Gas CCCT 2030 0 286 0 Storage 2032 5 5 0 Natural Gas Peaker 2033 47 47 0
Natural Gas Peaker 2034 0 0 47
Natural Gas Peaker 2035 0 0 192 Total 571 569 566

Demand Response 2025-2037 44 44 48
Conservation (w/ T&D losses) 2018-2037 107 107 108
Early Colstrip retirement decreases direct greenhouse gas emissions as shown in Figure 12.3. In the natural gas-fired peaker scenario, direct emissions decrease 62 percent in
1 The risk year is shifted to 2037 rather than 2030 used in other section to reflect change risk profile changes for portfolio choices late in the study period.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 188 of 205
2037 compared to the PRS. If a CCCT replaces Colstrip, direct emissions fall 44 percent.
The CCCT has higher direct emissions because it dispatches more hours than the less thermally efficient NG peaker. For the peaker scenario, Avista would rely on market purchases except when the peaker dispatch price is less expensive than purchasing from
the market. Another method to review this scenario is the implied cost of carbon of shutting down the units. Using the average cost change between 2031 and 2037 and dividing by the average direct emissions reduction is an implied cost of $17.41 per metric ton, this with the pricing included in the market price forecast totals $38.78 per metric ton.2 Figure 12.1: Colstrip Retires Scenario Cost versus Risk

2 This does not include indirect emissions from market purchases; depending on the methodology used to estimate these emissions the cost per ton could be higher. In the CCCT replacement scenario, the implied cost of carbon is $48.18 per metric ton using the same methodology.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 189 of 205
Figure 12.2: Annual Cost Impact with Colstrip Retirement versus PRS
Figure 12.3: Annual Greenhouse Gas Emissions with Colstrip Retirement

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 190 of 205
High-Cost Colstrip Retention Scenario
As part of the acceptance letter from the 2015 IRP, the Washington Commission requested a scenario with a higher than expected compliance costs to retain Colstrip and consult with the TAC regarding carbon pricing policies in the stochastic model. This
scenario includes the following assumptions: 1) The SCR is required by the end of 2023 instead of 2028 to reflect an expansion
of EPA regional air quality programs. 2) Units 1 & 2 shut down in 2018 rather than in 2022 and shift common facility costs earlier than in the Expected Case. 3) Adding a fabric filter (baghouse) system to enhance particulate removal by the end of 2023. 4) State of Montana to reduce carbon emissions beginning following the Clean
Power Plan’s mass based with new sources levels, but delayed until 2024.3
The annual cost between 2018 and 2037 is 3.7 percent higher in the High-Cost Colstrip scenario as compared to the PRS. Instead of paying these higher costs, the plant could
retire by 2023. Table 12.4 shows the resource strategy for a 2023 Colstrip retirement to avoid the High Cost Colstrip scenario assumptions. Shutting down the plant as compared to the High Colstrip Cost scenario would save customers 0.35 percent over running the plant for the remainder of the IRP study period. Figure 12.4 illustrates the cost and risk
of the portfolio compared to the PRS and the Expected Case’s Efficient Frontier. Both the high cost and retirement scenarios result in higher customer costs, but early retirement exposes customers to more volatile power supply costs. Figure 12.5 shows the annual
costs of the two scenarios compared to the PRS. Direct emissions for the PRS and the 2023 shutdown case are in Figure 12.6. Early retirement reduces emissions to 0.9 million metric tons if natural gas-fired peakers replace Colstrip and Lancaster and the wholesale
market serves some customer energy needs. The implied carbon cost of shutting down the plant between 2024 and 2037 by selecting the new resource strategy is an additional $12.21 per metric ton using the change in cost and the change in Avista’s direct emissions
from this scenario. This in total with the pricing included in the market analysis, totals $23.88 per metric ton.
3 The average shadow price of the stochastic studies is $11.67 per metric ton between 2024 and 2037. $6.47 in 2024 and $26.89 in 2037. The 95th percentile price in in 2024 is $16.94 per metric ton and $60.16 in 2037.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 191 of 205
Table 12.4: Colstrip Retires in 2023 Scenario Resource Strategy
Resource By End of Year
ISO Conditions (MW)
Natural Gas Peaker 2023 143
Thermal Upgrades 2023-2037 34
Natural Gas Peaker 2026 288
Natural Gas Peaker 2030 96
Storage 2035 5 Total 566 Demand Response 2025-2037 44 Conservation (w/ T&D losses) 2018-2037 107
Figure 12.2: High-Cost Colstrip Retention Scenario Efficient Frontier

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 192 of 205
Figure 12.3: High-Cost Colstrip Scenarios Annual Cost
Figure 12.4: Greenhouse Gas Emissions: Retire Colstrip in 2023 versus PRS

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 193 of 205
Colstrip Reduction Scenario
The major challenge with shutting down Colstrip prior to the end of its operational life is the cost to replace its generation capacity. An alternative to retiring Colstrip is reducing its dispatch. Each owner has dispatch rights and may not shut off all delivery, unless each
owner agrees. If the owners could agree, or if a program’s design could reduce dispatch within the constraints of each owner’s control, then this scenario could be a lower cost approach to reduce emissions than plant closure. For this scenario, a cap on emissions is set to 50 percent of Expected Case operations, and the plant is not able to purchase additional allowances. This methodology creates a carbon price for the emission reduction as described in Chapter 10. Figure 12.7, illustrates
the cost and risk changes of this scenario compared to the PRS and retiring Colstrip in 2030. The cost of dispatching Colstrip at a 50 percent level is 2.2 percent higher than the
Expected Case’s PRS. Retiring the plant in 2030 and replacing it with peakers is a 1.8
percent increase and replacing the plant with a CCCT is a 2.2 percent increase. Figure 12.8 shows the change in greenhouse gas emissions. Reducing dispatch to 50 percent levels is nearly on par from the customer cost point of view of shutting down the resource,
but if the plant needed to reduce operations less than 50 percent, then keeping the plant available is less costly. Figure 12.5: 50 Percent Colstrip Dispatch Reduction Scenario Cost & Risk Comparison

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 194 of 205
Figure 12.6: Colstrip Dispatch Reduction Scenario Greenhouse Gas Comparison
Other Resource Scenarios
Several other resource portfolio studies using the Expected Case’s market forecast formed the following analyses. The portfolios show the financial impact of different choices in meeting future resource deficits. Figure 12.9 shows the levelized cost and 2030
risk compared to the Efficient Frontier. Market Scenarios This plan includes two wholesale market portfolio scenarios; the first uses wholesale market purchases to meet all resource deficits with a load adjustment assuming conservation programs end. This scenario illustrates the cost to serve the system with market resources. The second market scenario limits new resources to conservation and
wholesale market purchases. These scenarios show the cost and risk if the utility chooses to depend on the wholesale market for its future needs. These portfolios estimate the value of capacity in the PRS.
If Avista ended conservation programs and used the wholesale power market for all future deficits, the cost to serve customers would be $22 million lower per year and market risk would be $12 million higher than the PRS. Offering conservation programs saves customers $23 million per year along with the market risk only being $1 million higher than the PRS. This analysis indicates that conservation is a cost effective method to reduce risk and cost to customers. It illustrates the cost to meet capacity requirements for
a reliable system adds $23 million per year to customer costs over depending on the wholesale market place.
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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 195 of 205
Figure 12.7: Other Resource Strategy Portfolio Cost and Risk (Millions)
No New Thermal Resources Scenario
The No New Thermal Resources scenario meets future resource deficits without adding carbon-emitting resources. It requires a mix of new resource options adding both capacity and energy to the system. Table 12.5 outlines the resources selected to meet Avista
capacity and energy requirements. If Avista could not construct or purchase new thermal resources, meeting capacity deficits would require new hydro and storage technologies, along with increased conservation and demand response. Wind and solar resources would meet energy requirements. This scenario is 4.1 percent higher cost than the PRS per year over the IRP study period, but the 2030 market risk is 2.7 percent lower. Greenhouse gas emissions are 22 percent lower than the PRS, when taking into account the added renewables to the overall system. This scenario would require additional reliability work to determine if storage technology and the wholesale market could together meet reliability requirements. This
scenario assumes over 10 percent of peak load is met by 215 MW of storage capacity and 645 MWh of storage capability. Avista will need to determine if current and large amounts of additional storage can adequately serve customer needs.

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Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 196 of 205
Table 12.5: No New Thermal Resource Scenario
Resource By End of Year
ISO Conditions (MW)
Storage 2026 150
Thermal Upgrades 2026-2030 44
Storage 2026-2037 65
Wind (on system) 2030 50
Hydro Upgrades 2030 68
Solar 2030-2037 250 Total 627
Demand Response 2025-2037 47 Conservation (w/ T&D losses) 2018-2037 123
Extending the no new thermal resources scenario to the Colstrip shut down in 2035 scenario requires additional storage and renewable resources. Table 12.6 outlines the resources selected to meet deficits in this case. This scenario results in significant increases in storage, hydro upgrades and solar resources at a capital cost exceeding $3.1 billion through 2037 compared to the $538 million included in the PRS. The cost, assuming Avista decisions do not affect market prices, is 9.7 percent higher than the PRS between 2018 and 2042. In 2036, the first full year of Colstrip retirement,
costs are 45 percent higher than the PRS, and 31 percent higher than replacing Colstrip with natural gas-fired peakers. Power Supply Cost volatility is 25 percent lower in this scenario than the PRS and 8 percent lower than replacing Colstrip with natural gas-fired
peakers in 2037. Greenhouse gas emissions are significantly lower. The direct greenhouse gas emissions from Avista facilities fall to 596,000 metric tons in 2037, but renewables added to the Avista system would offset these emissions. Even though this scenario is attractive from an environmental point-of-view, it has significant cost implications and reliability concerns. Additional studies are required to validate if there are any reliability concerns with meeting loads without baseload generation as a backstop during both poor hydro years and in peak winter conditions.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 197 of 205
Table 12.6: No New Thermal Resource and Colstrip Replacement Scenario
Resource By End of Year ISO Conditions (MW) Storage 2026 155 Thermal Upgrades 2026-2030 44 Storage 2027-2037 225 Wind (on system) 2030-2037 250 Solar 2030-2037 550
Hydro Upgrades 2035 148
Wind (Montana) 2036 100
Total 1,472

Demand Response 2025-2037 49
Conservation (w/ T&D losses) 2018-2037 124
Low Palouse Output Scenario Currently, Avista does not anticipate needing additional renewables to meet the Washington EIA due to control of Palouse Wind and ownership of Kettle Falls Generation
Station. Palouse Wind has delivered power for more than four years, but only one year has delivered the anticipated energy output. This scenario studies if Avista would require additional renewable energy if the generation continues to be below original expectations. The results of the scenario analysis warrant no change in resource strategy due to the inclusion of upgrades to Kettle Falls in the PRS. This analysis also indicates less REC sales (revenue) would be a result of lower Palouse Wind production. Given these conclusions, Avista will continue on its current EIA compliance path, but will continue to
monitor production levels for any significant changes. Increased Summer Planning Margin Scenario
As explained earlier, in recent IRPs Avista has not included any summer planning margin beyond expected load expectation and reserve requirements. This IRP adds a seven percent summer planning margin to the mandatory reserve requirements based on the shrinking regional capacity associated with the shutdown of coal plants. The seven percent planning margin is half of the winter planning margin. This scenario tests the potential requirement and portfolio changes for a 14 percent summer planning margin. Although, Avista does not currently anticipate moving to a 14 percent summer margin until the wholesale market fails to provide adequate capacity as determined by internal or NPCC studies. This study shows no significant change to the resource strategy until after 2035. The minor changes accelerate thermal upgrades in the PRS, although after 2035
solar resources are cost effective to provide summer peak reduction. New CCCT Replaces Lancaster Scenario
Previous IRP’s included a scenario regarding how the previous PRS compares to the new PRS. Since this plan’s new resource acquisition is significantly different from prior plans in both timing and resource choice, the best way to represent this type of analysis is by
including a new CCCT rather than CT’s to replace Lancaster as this is the major change with this plan. The levelized cost for this scenario is higher than the PRS by 0.85 percent
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 198 of 205
and 10 percent lower in 2030. In the Efficient Frontier analysis shown in Figure 12.7
above, the portfolio’s cost and risk is to the right of the Efficient Frontier. Indicating there are more optimal portfolios to achieve similar risk savings. Table 12.7 shows the resource strategy selection for this scenario. It is possible the CCCT is lower cost compared to
other alternatives so this portfolio option should be considered in future RFPs. Table 12.7: New CCCT Replaces Lancaster Scenario
Resource By End of Year ISO Conditions (MW)
CCCT 2026 285
Thermal Upgrades 2026-2037 34
Natural Gas Peaker 2030 47
Storage 2036 5
Total 371

Demand Response 2032-2037 35
Conservation (w/ T&D losses) 2018-2037 103
Washington State Emission Goal Analysis
The State of Washington has a goal to reduce greenhouse gas emissions to 20 percent below 1990 levels by 2035. No legislation or pathway to achieve this goal is set at the
time of the 2017 IRP analysis. Details regarding how to account for emissions from market purchases have not been determined. Lastly, allocation between Washington and Idaho will need resolution. Ignoring these issues, Figure 12.10 shows Avista’s total direct greenhouse gas emissions since 1990 and a 20-year forecast. Historical emissions are volatile due to hydro variability and resource changes. Avista significantly reduced its direct emissions in 2001 by selling its share of the Centralia coal plant, but emissions later rose due to Coyote Springs 2 and the Lancaster PPA. Hydro volatility needs addressing by any policy to reduce emissions because poor hydro years require thermal resources to meet load needs and they increase emissions in the regional power system.
Avista anticipates direct emissions to remain near 1990 levels and begin to decline under average water conditions, until reaching 20 percent below 1990 levels by 2035. After 2035, emissions begin to grow as Avista’s natural gas-fired facilities increase production
to meet load growth, unless future policies require changes to Avista’s dispatch or require the purchase of allowances to comply with state regulations. The Colstrip Reduction scenario level meets emission reduction goals. Retiring Colstrip in 2035 could reduce emissions by 60 percent compared to 1990 levels.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 199 of 205
Figure 12.8: Avista Direct Greenhouse Gas Emissions

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Schedule 9, Page 200 of 205

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 201 of 205
13. Action Items
The IRP is an ongoing and iterative process balancing regular publication timelines with pursuing the best 20-year resource strategies. 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 2015 IRP Action Plan and provides the 2015 Action Plan. Summary of the 2015 IRP Action Plan
The 2015 Action Plan included three categories: generation resource related analysis, energy efficiency, and transmission planning. 2015 Action Plan and Progress Report

Generation Resource Related Analysis
 Analysis of continued feasibility of the Northeast Combustion Turbine due to its age.
o Northeast is a 39 year old peaking unit permitted to run 100 run hours per year per unit. This action item is to determine if the unit should be available for the full 20-years of the IRP and if it should be considered for a capacity upgrade described in Chapter 9. Avista determined Northeast is a viable plant for the 20-year planning horizon. The plant has few
operating run hours and it is not expected to reach its next maintenance cycle for hot gas path inspection due to run hour limitations. The unit is designed and used to meet extreme peak load conditions and to provide
non-spinning reserves, it meets these needs at little cost to customers.

 Continue to review existing facilities for opportunities to upgrade capacity and
efficiency.
o Avista included several options to upgrade both hydro and thermal generating facilities in this IRP, these options are identified in Chapter 4. Further, Avista completed an upgrade to the Coyote Springs 2 facility in 2016, increasing winter peak capacity by 16 MW and increasing its efficiency by 0.8 percent by utilizing a hot gas path upgrade during its latest maintenance outage period.

 Increase the number of manufacturers and sizes of natural gas-fired turbines modeled for the PRS analysis.
o Avista reviewed the thermal generation sizes and manufacturers when
selecting resources to model for this IRP. Given Avista’s new generation capacity need is not until 2026, additional resources beyond those identified in Chapter 4 are unnecessary at this time. Avista studied many alternative natural gas-fired resources and selected the lowest cost and
sizeable resource to meet Avista’s deficits.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 202 of 205
 Evaluate the need for, and perform if needed, updated wind and solar integration studies.
o Avista determined it is not necessary to update or develop variable integration study at this time. This is due to the fact the generation and pricing scenarios used from the previous study are still relevant. Further, Avista prefers to conduct these updated studies using intra hour modeling
technology. This is currently being developed and may be available for the 2019 IRP.
 Participate and evaluate the potential to join a Northwest EIM.
o Avista is conducting a cost/benefit analysis associated with joining the CAISO EIM. This analysis will be complete in the fall of 2017. Avista is also evaluating other factors influencing the decision to join the CAISO EIM. These include the reduction of near term market liquidity as other utilities join the EIM and the additional integration of renewable resources in our service territory. Avista anticipates making a decision on joining the CAISO EIM and the associated timing by the end of 2017.
 Monitor regional winter and summer resource adequacy.
o Avista continues to monitor resource adequacy for both the Northwest and Avista. Avista is concerned the region may not have adequate resources
given announcements of large baseload plants, further, new analysis shown by the Northwest Power and Conservation Council show summer peaking is starting to be a concern. Given this change, Avista
implemented a 7 percent planning margin in the summer (in addition to operating reserves). Avista will continue to follow regional analysis by participating in the Resource Adequacy Advisory Committee.
 Participate in state level implementation of the CPP.
o Since the 2015 IRP, the Clean Power Plan is on hold by the US Supreme Court. Further, the new Federal Administration has appeared to pause the Clean Power Plan. This IRP does assume many of the goals of the CPP will ultimately be implemented at a later date. Energy Efficiency and Demand Response
 Continue to study and quantify transmission and distribution efficiency projects as they apply to EIA goals.
o This IRP includes new assumptions for T&D benefits based on new
analysis, as discussed in Chapter 5.
 Complete energy efficiency potential assessment on Avista’s generation facilities.
o Since the 2015 IRP, Avista has completed additional analysis on owned generation facilities, further, the costs have come down as some projects are lighting related. An updated analysis is provided in Chapter 5.
Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 203 of 205
Transmission and Distribution Planning
 Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for transmission service to bundled retail native load.
o Avista has maintained its existing transmission rights to meet native customer load.

 Continue to participate in BPA transmission processes and rate proceedings to
minimize the costs of integrating existing resources outside of Avista’s service area.
o Avista is actively participating in the BPA transmission rate proceedings.
 Continue to participate in regional and sub-regional efforts to establish new regional transmission structures to facilitate long-term expansion of the regional transmission
system.
o Avista staff participates in and leads many regional transmission efforts including the Columbia Grid and the Northern Tier Transmission Group Forums. 2017 IRP Two Year Action Plan
Avista’s 2017 PRS provides direction and guidance for the type, timing, and size of
future resource acquisitions. The 2017 IRP Action Plan highlights the activities planned for possible inclusion in the 2019 IRP. Progress and results for the 2017 Action Plan
items are reported to the TAC and the results will be included in Avista’s 2019 IRP. The 2017 Action Plan includes input from Commission Staff, Avista’s management team, and the TAC. Generation Resource Related Analysis
 Continue to review existing facilities for opportunities to upgrade capacity and efficiency.
 Model specific commercially available storage technologies within the IRP; including efficiency rates, capital cost, O&M, life cycle, and ability to provide non-power supply benefits.
 Update the TAC regarding the EIM study and Avista plan of action.
 Monitor regional winter and summer resource adequacy, provide TAC with additional Avista LOLP study analysis.
 Update the TAC regarding progress regarding Post Falls Hydroelectric Project
redevelopment.
 Perform a study to determine ancillary services valuation for storage and peaking technologies using intra hour modeling capabilities. Further, use this technology to estimate costs to integrate variable resources.
 Monitor state and federal environmental policies effecting Avista’s generation fleet.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 204 of 205
Energy Efficiency and Demand Response
 Determine whether or not to move the T&D benefits estimate to a forward looking value versus a historical value.
 Determine if a study is necessary to estimate the potential and costs for a winter and summer residential demand response program and along with an update to the existing commercial and industrial analysis.
 Use the utility cost test methodology to select conservation potential for Idaho program options.
 Share proposed energy efficiency measure list with Advisory Groups prior to CPA completion.
Transmission and Distribution Planning
 Work to maintain Avista’s existing transmission rights, under applicable FERC policies, for transmission service to bundled retail native load.
 Continue to participate in BPA transmission processes and rate proceedings to minimize costs of integrating existing resources outside of Avista’s service area.
 Continue to participate in regional and sub-regional efforts to facilitate long-term
economic expansion of the regional transmission system.
 IRP & T&D planning will coordinate on evaluating opportunities for alternative
technologies to solve T&D constraints.

Exhibit No. 7 Case No. AVU-E-21-01 S. Kinney, Avista
Schedule 9, Page 205 of 205