20230531Integrated Resource Plan.pdf

A vista Corp.
1411 East Mission P.O. Box 3727
Spokane, Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
June 1, 2023
Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd. Bldg. 8, Ste. 201-A
Boise, Idaho 83 714
RE: Case No. AVU-E-23-_-Avista's 2023 Electric Integrated Resource Plan
Dear Ms. Noriyuki:
A vista Corporation d/b/a/ A vista Utilities, hereby submits for filing with the Commission its final
2021 Electric Integrated Resource Plan (IRP). Supporting documents can be found on the provided
USB drive and on Avista's website at https://myavista.com/about-us/integrated-resource­
planning.
If you have any questions regarding this filing, please contact James Gall at 509-495-2189 or John
Lyons at 509-495-8515.
Sincerely,
Shawn Bonfield
Sr. Manager of Regulatory Strategy & Policy
509-434-6502
[e-mail]
RECEIVED
Wednesday, May 31, 2023 4:10:09 PM
IDAHO PUBLIC
UTILITIES COMMISSION
CASE NO. AVU-E-23-05
2 0 2 3
Electric Integrated
Resource Plan
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.
Production Credits
John L ons
Lori Hermanson IRP Core Team
Mike Hermanson IRP Core Team
Tom Pardee IRP Core Team
Michael Brutocao IRP Core Team
Grant Fors th Chief Economist Load Forecast
& Anal sis
Electric IRP Contributors
Name Title Contribution
Scott Kinney VP of Enerqy Resources Power Suoolv
Kevin Holland Director of Enerqy Supply Power Supply
Clint Kalich Sr. Manager of Resource Analysis Power Supply
Chris Drake Manaqer of Resource Optimization Power Suoolv
Ben Kropelnicki Student Intern Power Supply
Annette Brandon Wholesale Marketing Manaqer Power Suoolv/CEIP
Tamara Bradley Customer Enqaqement Manaqer CEIP
Kim Boynton Sr. Data Science Analyst CEIP
Harrison Fine Data Science Analyst CEIP
Darrell Soyars Mgr. Corporate Environmental Compliance Environmental
Janna Loeookv Greenhouse Gas Compliance Proqram Mqr. Environmental
John Gross Mqr. of System Planninq System Planninq
Damon Fisher Principle Engineer Distribution Planninq
Rendall Farley Manaqer of Electric Transportation Electrification
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory
Amanda Gherinq Requlatorv Affairs Analyst Requlatorv
Annie Gannon Communications Manager Communications
Marv Tyrie Manaqer Corporate Communications Communications
Contact contributors via email by placing their names in this email address format:
first. [e-mail]
2023 Electric IRP
Executive Summary
Avista has a 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.
Avista secured several new supply contracts since the 2021 IRP including
additional slices of Chelan PUD's Rock Island and Rocky Reach hydro facilities,
Columbia Basin Hydro Power's irrigation generation facilities, planned upgrades
to Avista's Kettle Falls and Post Falls generation facilities, a 30-year wind PPA 1,
and an extension of the current agreement for output from the Lancaster Combined
Cycle Combustion Turbine (CCCT). These resources, as summarized in the figure
below, will meet Avista's expected energy and capacity needs through the middle
of the 2030s. In addition to resource acquisitions, Avista agreed to end its use of
coal by transferring ownership of Colstrip Units 3 & 4 to Northwestern Energy at
the end of 2025.
Industrial Demand Response
Chelan PUD's Rock Island &
Rocky Reach (#2)
Columbia Basin Hydro's
Irrigation Generation
Chelan PUD's Rock Island &
Rocky Reach (#3)
Kettle Falls Biomass Upgrade
30-Year Wind PPA
Colstrip 3 &4
Lancaster CCCT
Post Falls Hydro Upgrade
Announced Resource Changes (MW)
30MW
87.5MW
283MW
6.4MW
... '° M M 0 0 N N
u:>r--.a:>m M M M M 0 0 0 0 N N N N
0 c5 c5 N N
The 2023 Integrated Resource Plan (IRP) updates Avista's load forecast,
distributed energy resources (DER) including an energy efficiency and demand
response assessment, supply-side resource options cost and generic operating
characteristics, and the load-resource position. It includes a Preferred Resource
Strategy (PRS) summarizing a mix of planned resource types to meet future
customer demand and state energy goals.
1 Avista will identify this project at a later date.
Avista Corp 2023 Electric IRP
2023 IRP Highlights
Major changes from the 2021 IRP include:
• Progress on Washington's Clean Energy Implementation Plan's (CEIP)
Customer Benefit Indicators (CBls) especially those relevant to resource
modeling. A forecast of new projects funded by the Named Community
Investment Fund (NCIF) is also included.
• Increased load forecast from higher expectations for transportation and
building electrification .
• Reduced energy efficiency targets due to lower avoided costs and lower
potential opportunities with stronger codes and standards.
• Incorporates future hydro and temperature conditions based on the
Representative Concentration Pathways (RCP) 4.5 forecast.
Preferred Resource Strategy
Avista estimates customer loads will increase 0.86% annually, but winter and
summer peak demand will grow by 1.16% and 1.24% respectively. With the
resource additions above, A vista's resource strategy focus for the next 10 years is
to continue investing in energy efficiency meeting 27% of future load growth and
reducing loads by 85 aMW through 2045. Avista will achieve equitable outcomes
for its Washington service area by engaging disadvantaged communities through
the Company's NCIF, with potential programs such as community solar, energy
storage, and targeted energy efficiency. The company will also leverage demand
response pilots such as Time of Use Rates (TOU), Peak Time Rebate (PTR), and
water heater direct control programs to determine the programs most valuable to
our customers.
Avista refines its resource selection by selecting resources for Idaho and
Washington separately to meet monthly energy and capacity targets. The table
below outlines the complete list of new generating and storage resources required
to meet future resource deficits. For Washington loads, beginning in 2030, the plan
calls for investing in 400 MW of wind followed by long-duration storage resources
beginning in 2036 using renewable liquid fuels such as ammonia and/or green
hydrogen, as well as iron-oxide storage technologies. For Idaho, the plan calls for
natural gas peaking resources beginning in 2034 to replace resource retirements
and meet load growth, along with a small amount of long duration storage
beginning in 2043.
With these resource additions, the energy system is capable of generating 92% of
the load with clean energy resources and will meet 100% of Washington's load
with clean resources on average for each month. Also, by 2045, greenhouse gas
emissions are 80% lower than the 2021 levels.
Avista Corp 2023 Electric IRP ii
2023 IRP Preferred Resource Strategy
Resource Time Jurisdiction Capacity Energy
Period (MW) Capability
(aMW)
NW Wind 2030 WA 200 63
Montana Wind 2032 WA 200 97
Natural Gas CT 2034 ID 90 86
Renewable Fueled CT 2036 WA 88 31
Long Duration Storage (>24 hr) 2039 WA 52 -1
PPA Wind Renewal 2041 WA 140 53
Renewable Fueled CT 2041 WA 74 26
Natural Gas (ICE) 2041 ID 46 46
PPA Wind Renewal 2042 WA 105 36
Renewable Fueled CT 2042 WA 186 65
Natural Gas CT 2042 ID 102 97
Long Duration Storage (>24 hr) 2043 WA/ID 68 -1
NW Wind 2044 WA 100 31
Long Duration Storage (>24 hr) 2044 WA/ID 50 -1
NW Wind 2045 WA 200 63
Renewable Fueled CT 2045 WA 348 122
Natural Gas (ICE) 2045 ID 65 65
Short Duration Storage (<8 hr) 2045 ID 25 0
Total New Resources 2,139 878
The new resource choices will result in above average inflation of the retail rate. In
Washington, projected rates increase at 3.4% per year on average, but 6.41 % per
year in the last 5 years of the study ending at 23.4 cents per kWh . For Idaho,
projected rates grow at a slower pace of 2. 7% per year and 4.2% in the last 5 years
of the plan for a 2045 rate of 18.5 cents per kWh.
Avista Corp 2023 Electric IRP iii
Alternative Resource Strategies Analysis
Avista studied 17 alternative resource portfolio scenarios to test higher levels of
renewable energy for Idaho, additional transportation and building electrification
load, resource adequacy requirements, and the impacts of resource strategies only
focusing on customer impacts other than cost. Some of the result highlights
include:
• Transitioning 100% of Avista's resource portfolio to clean energy by 2045
would increase Idaho's rates by 40% adding 7.5 cents per kWh , vastly
exceeding the 2-5% increase customers indicated by survey they are
willing to pay for carbon reductions.
• A study where Washington electrifies 80% of the natural gas distribution
system with high levels of transportation electrification results in 33%
higher rates by 2045 due to the incremental resource need and upgrading
the transmission and distribution system . Distribution system upgrades
alone results in a 4 cent/kWh increase.
• A scenario to identify resource choice changes using social impacts to
Idaho resulted in higher renewable energy selection with a 1.8% rate
increase, well within the customer tolerance. Although the most interesting
result of this scenario shows Washington's 100% transition goals increase
customer rates by more than the societal benefits.
• Avista found moving to the Western Resource Adequacy Program (WRAP)
planning margins will not substantially change the resource strategy.
Depending on the amount of level of Qualifying Capacity Credits (QCC) the
WRAP assigns our resources will impact the strategy by changing the
required duration of energy storage needs.
IRP Process
Each IRP is a thoroughly researched plan using a robust data-driven approach
identifying a PRS that meets customer needs while balancing costs and risk
measures with environmental goals and mandates. The 2023 IRP cycle included
nine public meetings with Avista's Technical Advisory Committee (TAC) and one
public meeting, where Avista presented assumptions, methodologies, and results
of planning analyses for public review and comment. Participants in the public
process include customers, academics, environmental organizations, government
agencies, consultants, utilities, elected officials, state utility commission
stakeholders, and other interested parties.
Avista Corp 2023 Electric IRP iv
Table of Contents
1. lntroduction .................................................................................................................... 1-1
IRP Process ............................................................................................................................. 1-1
Washington Progress Report Requirements ........................................................................... 1-5
Idaho Regulatory Requirements .............................................................................................. 1-8
Summary of Changes from the 2021 IRP .............................................................................. 1-13
2023 IRP Chapter Outline ...................................................................................................... 1-15
2023 IRP Appendices ............................................................................................................. 1-16
2. Economic & Load Forecast .......................................................................................... 2-1
Economic Characteristics of Avista's Service Territory ............................................................ 2-1
Long-Term Load Forecast. ..................................................................................................... 2-12
Monthly Peak Load Forecast Methodology ............................................................................ 2-19
Scenario Analysis ................................................................................................................... 2-23
3. Existing Supply Resources .......................................................................................... 3-1
Spokane River Hydroelectric Developments ........................................................................... 3-3
Clark Fork River Hydroelectric Development.. ......................................................................... 3-4
Total Hydroelectric Generation ................................................................................................ 3-4
Thermal Resources .................................................................................................................. 3-5
Small Avista-Owned Solar ....................................................................................................... 3-9
Power Purchase and Sale Contracts ....................................................................................... 3-9
Natural Gas Pipeline Rights ................................................................................................... 3-13
Resource Environmental Requirements and Issues .............................................................. 3-15
4. Long-Term Position ....................................................................................................... 4-1
Capacity Requirements ............................................................................................................ 4-1
Energy Requirements ............................................................................................................... 4-6
Forecasted Temperature & Precipitation Analysis ................................................................... 4-8
Washington State Renewable Portfolio Standard .................................................................. 4-12
Washington State Clean Energy Transformation Act ............................................................ 4-13
Resource Adequacy Risk Assessment .................................................................................. 4-15
5. Distributed Energy Resources ..................................................................................... 5-1
Energy Efficiency ...................................................................................................................... 5-1
Demand Response Potential Study ......................................................................................... 5-8
Distributed Generation Resources ......................................................................................... 5-17
DER Evaluation Methodology ................................................................................................ 5-19
DER Potential Study ............................................................................................................... 5-21
6. Supply-Side Resource Options .................................................................................... 6-1
Assumptions ............................................................................................................................. 6-1
Thermal Resource Upgrade Options ..................................................................................... 6-20
Variable Energy Resource Integration Cost ........................................................................... 6-20
Sub Hourly Resource and Ancillary Services Benefits .......................................................... 6-21
Qualifying Capacity Credit ...................................................................................................... 6-22
Other Environmental Considerations ..................................................................................... 6-23
Non-Energy Impacts ............................................................................................................... 6-25
7. Transmission & Distribution Planning ........................................................................ 7-1
Avista Transmission System .................................................................................................... 7-1
Transmission Planning Requirements and Processes ............................................................ 7-3
System Planning Assessment .................................................................................................. 7-4
Generation Interconnection ...................................................................................................... 7-5
Distribution Resource Planning ................................................................................................ 7-8
Merchant Transmission Rights ............................................................................................... 7-13
8. Market Analysis ............................................................................................................. 8-1
Electric Marketplace ................................................................................................................. 8-1
Western Interconnect Loads .................................................................................................... 8-3
Generation Resources ............................................................................................................. 8-5
Avista Corp 2023 Electric IRP V
Generation Operating Characteristics ...................................................................................... 8-7
Electric Market Price Forecast ............................................................................................... 8-19
9. Preferred Resource Strategy ........................................................................................ 9-1
Resource Selection Process .................................................................................................... 9-3
Preferred Resource Strategy DER Selections ......................................................................... 9-5
Preferred Resource Strategy Resource Selections ............................................................... 9-10
Market Risk Analysis .............................................................................................................. 9-17
Environmental Impacts ........................................................................................................... 9-22
Cost and Rate Projections ..................................................................................................... 9-26
Avoided Cost .......................................................................................................................... 9-28
10. Portfolio Scenario Analysis ........................................................................................ 10-1
Portfolio Scenarios ................................................................................................................. 10-2
Cost & Rate Impact Summary .............................................................................................. 10-12
Greenhouse Gas Emission Comparison .............................................................................. 10-18
Market Price Sensitivities ..................................................................................................... 10-20
11. Washington Customer Impacts .................................................................................. 11-1
Equity Impacts ........................................................................................................................ 11-2
Named Community Identification ........................................................................................... 11-3
Non-Energy Impacts (NEI) ..................................................................................................... 11-7
Named Community Investment Fund ..................................................................................... 11-8
Customer Benefit Indicators ................................................................................................... 11-9
12. Action Items ................................................................................................................. 12-1
2021 IRP Action Items ............................................................................................................ 12-1
2023 IRP Action Items ............................................................................................................ 12-4
Avista Corp 2023 Electric IRP vi
Table of Figures
Figure 2.1: MSA Population Growth and U.S. Recessions, 1971-2021 ....................................... 2-2
Figure 2.2: Avista and U.S. MSA Population Growth, 2012-2021 ................................................ 2-3
Figure 2.3: MSA Non-Farm Employment Breakdown by Major Sector, 2021 .............................. 2-3
Figure 2.4: Avista and U.S. MSA Non-Farm Employment Growth, 2012-2021 ........................... 2-4
Figure 2.5: MSA Personal Income Breakdown by Major Source, 2021 ....................................... 2-5
Figure 2.6: Avista and U.S. MSA Real Personal Income Growth by Decade, 1970-2021 ........... 2-5
Figure 2.7: Forecasting IP Growth ................................................................................................ 2-9
Figure 2.8: Industrial Load and Industrial (IP) Index .................................................................... 2-9
Figure 2.9: Population Growth vs. Customer Growth, 2000-2021 ............................................. 2-11
Figure 2.10: Forecasting Population Growth .............................................................................. 2-11
Figure 2.11 : Long-Term Annual Residential Customer Growth ................................................. 2-13
Figure 2.12: Electric Vehicle and Rooftop Solar Load Changes ................................................ 2-16
Figure 2.13: UPC Growth Forecast Comparison to EIA ............................................................. 2-17
Figure 2.14: Load Growth Comparison to EIA ........................................................................... 2-17
Figure 2.15: Load Share Comparison Due to Temperature Forecasts ...................................... 2-18
Figure 2.16: Load Share Comparison Due to Temperature Assumptions ................................. 2-19
Figure 2.17: Peak Load Forecast.. ............................................................................................. 2-22
Figure 2.18: Peak Load Forecast with 1-in-20 High/Low Bounds .............................................. 2-22
Figure 2.19: Average Megawatts, High/Low Economic Growth Scenarios ................................ 2-25
Figure 2.20: Full Building Electrification -Energy Impact.. ........................................................ 2-26
Figure 2.21 : Full Building Electrification -Winter Peak Impact.. ................................................ 2-27
Figure 2.22: Full Building Electrification -Summer Peak Impact .............................................. 2-27
Figure 2.23: Hybrid Electrification -Energy Impact ................................................................... 2-28
Figure 2.24: Hybrid Electrification -Winter Peak Impact.. ......................................................... 2-28
Figure 2.25: Hybrid Electrification -Summer Peak Impact.. ...................................................... 2-29
Figure 2.26: High EV Adoption -Energy Impact ........................................................................ 2-30
Figure 2.27: High EV Adoption -Winter Peak Impact ............................................................... 2-30
Figure 2.28: High EV Adoption -Summer Peak Impact.. .......................................................... 2-31
Figure 2.29: Full Electrification and High EV and Solar Adoption -Energy Impact ................... 2-32
Figure 2.30: Full Electrification and High EV and Solar Adoption -Winter Peak Impact .......... 2-32
Figure 2.31: Full Electrification and High EV and Solar Adoption -Summer Peak Impact.. ..... 2-33
Figure 3.1 : 2024 Avista Seasonal Capability ................................................................................ 3-1
Figure 3.2: 2024 Annual Energy Capability .................................................................................. 3-2
Figure 3.3: 2021 Avista's Washington State Fuel Mix Disclosure ................................................ 3-2
Figure 3.4: Avista Firm Natural Gas Pipeline Rights .................................................................. 3-14
Figure 4.1: Winter One-Hour Peak Capacity Load and Resources Balance ............................... 4-5
Figure 4.2: Summer One-Hour Peak Capacity Load and Resources Balance ............................ 4-5
Figure 4.3: Comparison of Energy Contingency Methodology ..................................................... 4-7
Figure 4.4: Comparison of Recent 80-Year, Recent 30-Year, and RCP 4.5 Generation ........... 4-10
Figure 4.5: Impact of RCP 4.5 Temperature Data on Load Forecast ........................................ 4-11
Figure 4.6: Washington State CETA Compliance Position ........................................................ 4-15
Figure 5.1: Historical Conservation Acquisition (system) ............................................................. 5-2
Figure 5.2: Analysis Approach Overview ..................................................................................... 5-3
Figure 5.3: Jurisdiction Supply Curve ........................................................................................... 5-5
Figure 5.4: Program Characterization Process .......................................................................... 5-10
Figure 5.5: Demand Response QCC Forecast for 4-hour Program ........................................... 5-16
Figure 5.6: A vista's Net Metering Customers ............................................................................. 5-17
Figure 6.1: Storage Upfront Capital Cost versus Duration ........................................................... 6-9
Figure 6.2: Lithium-ion Capital Cost Forecast.. .......................................................................... 6-11
Figure 6.3: Wholesale Green Hydrogen Costs per Kilogram ..................................................... 6-14
Figure 6.4: QCC Forecast for VER and Energy Storage ............................................................ 6-23
Figure 6.5: Social Cost of Greenhouse Gas ............................................................................... 6-24
Figure 7.1: Avista Transmission System ...................................................................................... 7-1
Avista Corp 2023 Electric IRP vii
Figure 7.2: Avista 230 kV Transmission System .......................................................................... 7-2
Figure 7.3: NERC Interconnection Map ....................................................................................... 7-3
Figure 8.1: NERC Interconnection Map ....................................................................................... 8-2
Figure 8.2: 22-Year Annual Average Western Interconnect Load Forecast ................................ 8-4
Figure 8.3: Cumulative Resource Retirement Forecast ............................................................... 8-5
Figure 8.4: Western Generation Resource Additions (Nameplate Capacity) ............................... 8-7
Figure 8.5: Henry Hub Natural Gas Price Forecast ...................................................................... 8-8
Figure 8.6: Stochastic Stanfield Natural Gas Price Forecast.. ..................................................... 8-9
Figure 8.7: Stanfield Nominal 20-Year Nominal Levelized Price Distribution ............................ 8-10
Figure 8.8: Northwest Hydro Generation Comparison ............................................................... 8-11
Figure 8.9: Northwest Expected Energy ..................................................................................... 8-12
Figure 8.10: Carbon Price Comparison ...................................................................................... 8-15
Figure 8.11 : WECC Generation Technology History and Forecast ........................................... 8-16
Figure 8.12: Northwest Generation Technology History and Forecast ...................................... 8-16
Figure 8.13: 2020 and 2045 Greenhouse Gas Emissions ......................................................... 8-17
Figure 8.14: Greenhouse Gas Emissions Forecast ................................................................... 8-18
Figure 8.15: Northwest Regional Greenhouse Gas Emissions Intensity ................................... 8-19
Figure 8.16: Mid-Columbia Electric Price Forecast Range ........................................................ 8-20
Figure 8.17: Winter Average Hourly Electric Prices (December -February) ............................. 8-22
Figure 8.18: Spring Average Hourly Electric Prices (March -June) ........................................... 8-22
Figure 8.19: Summer Average Hourly Electric Prices (July -September) ................................. 8-23
Figure 8.20: Autumn Average Hourly Electric Prices (October -November) ............................. 8-23
Figure 9.1 : Announced Resource Changes Since 2021 IRP ....................................................... 9-2
Figure 9.2: Energy Efficiency Annual Forecast ............................................................................ 9-8
Figure 9.3: Energy Efficiency Savings Programs by Share of Total ............................................ 9-9
Figure 9.4: Washington Annual Achievable Potential Energy Efficiency (Gigawatt Hours) ....... 9-10
Figure 9.5: System Winter Capacity Load & Resources ............................................................ 9-15
Figure 9.6: System Summer Capacity Load & Resources ......................................................... 9-15
Figure 9.7: System Annual Energy Load & Resources .............................................................. 9-16
Figure 9.8: System Clean Energy Ratio Compared to Load (Select Years) .............................. 9-23
Figure 9.9: Clean Energy to Retail Load Comparison (CETA Requirements) ........................... 9-24
Figure 9.10: System Greenhouse Gas Emissions ..................................................................... 9-25
Figure 9.11: System Greenhouse Gas Emissions Intensity ....................................................... 9-25
Figure 9.12: Avista Owned and Controlled Generating Plant Air Emissions ............................. 9-26
Figure 9.13: Revenue Requirement and Rate Forecast by State .............................................. 9-27
Figure 9.14: Washington Energy Efficiency Avoided Cost.. ....................................................... 9-29
Figure 9.15: Idaho Energy Efficiency Avoided Cost.. ................................................................. 9-29
Figure 10.1: PVRR Summary ................................................................................................... 10-14
Figure 10.2: Washington Energy Rate Comparison ................................................................. 10-15
Figure 10.3: Idaho Energy Rate Comparison ........................................................................... 10-15
Figure 10.4: System Cost versus Risk Comparison ................................................................. 10-16
Figure 10.5: Portfolio PVRR with Risk Analysis ....................................................................... 10-17
Figure 10.6: 2045 System Energy Cost w/ Risk ....................................................................... 10-18
Figure 10.7: Emission Reduction (Millions of Metric Tons (2045 compared to 2024) .............. 10-19
Figure 10.8: Change in Emissions Compared to Portfolio PVRR ............................................ 10-20
Figure 11.1: Named Communities .............................................................................................. 11-4
Figure 11.2: Spokane Named Communities .............................................................................. 11-5
Figure 11.3: Washington Service Area Named Communities .................................................... 11-6
Figure 11.4: Clarkston Area Named Communities ..................................................................... 11-7
Figure 11 .5: Planning Process ................................................................................................. 11-10
Figure 11.6: WA Customers with Excess Energy Burden (Before Energy Assistance) ........... 11-18
Figure 11 . 7: Percent of Washington Customers with Excess Energy Burden ......................... 11-18
Figure 11.8: Average Washington Customer Excess Energy Burden ..................................... 11-19
Figure 11 .9: Total MWh of DER in Named Communities ......................................................... 11-20
Figure 11 .10: Total MWh Capability of Storage DER in Named Communities ........................ 11-20
Figure 11 .11: Total MWh Capability of Storage DER in Named Communities ........................ 11-21
Avista Corp 2023 Electric IRP viii
Figure 11 .12: Planning Reserve Margin ................................................................................... 11-22
Figure 11 .13: Generation in Washington and/or Connected to Avista Transmission .............. 11-23
Figure 11 .14: Avista Located Washington State Facility's SO2 Emissions ............................... 11-24
Figure 11.15: Avista's Washington State Facility's NOx Emissions .......................................... 11-25
Figure 11 .16: Avista's Washington State Facility's voe Emissions ......................................... 11-25
Figure 11.17: Washington Direct and Net Emissions ............................................................... 11-26
Figure 11 .18: Avista Washington Service Area Direct and Net Emissions .............................. 11-27
Avista Corp 2023 Electric IRP ix
Table of Tables
Table 1 .1: TAC Meeting Dates and Agenda Items ....................................................................... 1-2
Table 1.2: External Technical Advisory Committee Participating Organizations ......................... 1-4
Table 1.3: Washington Progress Report Requirement Discussions ............................................ 1-5
Table 2.1: UPC Models Using Non-Weather Driver Variables ..................................................... 2-8
Table 2.2: Customer Growth Correlations, 1998 -2021 ............................................................ 2-10
Table 2.3: Forecasted Winter and Summer Peak Growth, 2021-2045 ...................................... 2-21
Table 2.4: Energy and Peak Forecasts ...................................................................................... 2-23
Table 2.5: High/Low Economic Growth Scenarios (2027-2045) ................................................ 2-25
Table 2.6: Load Growth for High/Low Economic Growth Scenarios (2023-2045) ..................... 2-26
Table 2.7: EV Percent of Sales Comparison between Expected and Scenario ......................... 2-29
Table 2.8: WA Solar Percent of Customer Comparison between Expected and Scenario ........ 2-31
Table 3.1: Avista-Owned Hydroelectric Resources ...................................................................... 3-4
Table 3.2: Avista-Owned Thermal Resources .............................................................................. 3-5
Table 3.3: Avista-Owned Thermal Resource Capability .............................................................. 3-5
Table 3.4: Current Colstrip Ownership Shares ............................................................................. 3-6
Table 3.5: Avista-Owned Solar Resource Capability ................................................................... 3-9
Table 3.6: Mid-Columbia Capacity and Energy Contracts ......................................................... 3-10
Table 3.7: Columbia Basin Hydro Projects ................................................................................. 3-10
Table 3.8: PURPA Agreements .................................................................................................. 3-11
Table 3.9: PURPA Agreements (net meter only) ....................................................................... 3-11
Table 3.10: Other Contractual Rights and Obligations ............................................................... 3-13
Table 3.11 : Top Five Historical Peak Day Natural Gas Usage (Dekatherms) ........................... 3-14
Table 3.12: Avista Owned and Controlled PM Emissions .......................................................... 3-18
Table 4.1: Avista 2023 Summer and 2023-2024 Winter Metrics (MW) ........................................ 4-4
Table 4.2: Monthly Energy Evaluation Methodologies ................................................................. 4-6
Table 4.3: Net Energy Position ..................................................................................................... 4-8
Table 4.4: Comparison of Temperature Increases by Representative Concentration Pathway .. 4-9
Table 4.5: 80-Year, Recent 30-Year, and RCP 4.5 Hydro Generation Forecast Comparison .. 4-10
Table 4.6: Washington State EIA Compliance Position Prior to REC Banking (a MW) .............. 4-12
Table 4.7: CETA Compliance Target Assumpions ..................................................................... 4-13
Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years) ...................... 5-5
Table 5.2: Demand Response Program Options by Market Segment ....................................... 5-11
Table 5.3: DR Program Steady-State Participation Rates (Percent of Eligible Customers) ...... 5-14
Table 5.4: System Program Cost and Potential ......................................................................... 5-15
Table 5.5: Avista-Owned Solar Resource Capability ................................................................. 5-18
Table 5.6: DER Generation & Storage Options Size and Cost .................................................. 5-18
Table 5.7: DER Cost & Benefit Impacts ..................................................................................... 5-20
Table 5.8: DER Potential Study Schedule .................................................................................. 5-22
Table 6.1 : Natural Gas-Fired Plant Levelized Costs .................................................................... 6-5
Table 6.2: Natural Gas-Fired Plant Cost and Operational Characteristics ................................... 6-5
Table 6.3: Forecasted Solar and Wind Capital Cost ($/kW) ........................................................ 6-7
Table 6.4: Forecasted Solar and Wind O&M ($/kW-yr.) ............................................................... 6-7
Table 6.5: Levelized Solar and Wind Prices ($/MWh) .................................................................. 6-7
Table 6.6: Additional Levelized Cost for Combined Lithium-Ion Storage Solar Facility ($/kW-
month) .................................................................................................................................. 6-8
Table 6.7: Pumped Hydro Options Cost ($/kW-month) .............................................................. 6-10
Table 6.8: Lithium-Ion Levelized Cost ($/kW-month) ................................................................. 6-11
Table 6.9: Storage Levelized Cost ($kW-Month) ....................................................................... 6-13
Table 6.10: Hydrogen Based Resource Option Costs ............................................................... 6-16
Table 6.11: Ancillary Services and Sub-hourly Value Estimates (2023 dollars) ........................ 6-22
Table 6.12: New Resource QCC Values .................................................................................... 6-22
Table 6.13: IRP Resource NEI Values ....................................................................................... 6-26
Table 7.1: 2023 IRP Generation Study Transmission Costs ........................................................ 7-6
Avista Corp 2023 Electric IRP X
Table 7.2: Third-Party Large Generation Interconnection Requests ............................................ 7-7
Table 7.3: T&D Requirements for the Combined Electrification Scenario ................................. 7-13
Table 7.3: Merchant Transmission Rights .................................................................................. 7-13
Table 8.1: AURORA Zones .......................................................................................................... 8-2
Table 8.2: Natural Gas Price Basin Differentials from Henry Hub ............................................... 8-9
Table 8.3: Nominal Levelized Flat Mid-Columbia Electric Price Forecast... ............................... 8-20
Table 8.4: Annual Average Mid-Columbia Electric Prices ($/MWh) ........................................... 8-21
Table 9.1: NCIF Resource Selection ............................................................................................ 9-7
Table 9.2: Biennial Conservation Target for Washington Energy Efficiency .............................. 9-10
Table 9.3: Resource Retirements and Exits ............................................................................... 9-11
Table 9.4: Resource Selections (2024-2035) ............................................................................. 9-12
Table 9.5: Resource Selections (2036-2045) ............................................................................. 9-13
Table 9.6: 2030 Average Market Purchases with 330 MW Market Limit (aMW) ....................... 9-19
Table 9.7: 2030 Average Market Purchases with 1,000 MW Market Limit (aMW) .................... 9-20
Table 9.8: 2045 Average Market Purchases with 330 MW Market Limit (a MW) ....................... 9-21
Table 9.9: 2045 Average Market Purchases with 1,000 MW Market Limit (aMW) .................... 9-22
Table 9.10: 2022-2024 Cost Cap Analysis (millions $) .............................................................. 9-28
Table 9.11: New Resource Avoided Costs ................................................................................. 9-32
Table 10.1: Resource Selection Summary by Portfolio Scenario in MW (Washington) ............. 10-4
Table 10.2: Resource Selection Summary by Portfolio Scenario in MW (Idaho) ....................... 10-4
Table 10.3: Resource Selection Summary by Portfolio Scenario .............................................. 10-5
Table 10.4: Jurisdiction Cost and Rate Summary .................................................................... 10-13
Table 10.5: PVRR and Emission Changes .............................................................................. 10-21
Table 10.6: Jurisdiction PVRR Sensitivity Analysis .................................................................. 10-22
Table 11.1: Named Communities ............................................................................................... 11-3
Table 11.2: Customer Benefit Indicators .................................................................................. 11-11
Avista Corp 2023 Electric IRP xi
Appendix Table of Contents
Appendix A-2023 IRP Technical Advisory Committee Presentations
Appendix B -2023 Electric IRP Work Plan
Appendix C -AEG Conservation and Demand Response Potential Assessment
Appendix D -DNV Non-Energy Impact Studies
Appendix E -Transmission Designated Network Study
Appendix F -Inputs and Results
Appendix G -DER Scope of Work
Appendix H -Confidential Historical Generation Operation Data
Appendix I -New Resource Table for Transmission
Appendix J -Confidential Inputs and Models
Appendix K -Resource Portfolio Summary
Appendix L -Public Comments
Avista Corp 2023 Electric IRP xii
Chapter 1: Introduction
1. Introduction
Avista is a multijurisdictional utility serving electric customers in Washington and Idaho.
Both states have rules and regulations regarding filing dates, content, and methods used
to develop electric integrated resource plans. Avista endeavors to consolidate state
requirements into one plan filed every other year. Avista was able to adjust its filing date
for the 2023 Electric Integrated Resource Plan (IRP) in Idaho to June 2023 due to
finalizing the 2022 All-Source Request for Proposal. In addition, Avista also filed an IRP
progress report in its January 2023 Washington Progress Report filing to meet a separate
filing requiring, which did not include all resources acquired from the RFP. As such , this
is an update to the prior filing progress report filing.
The energy planning requirements between Avista's two jurisdictions could not be more
different. In Idaho, the focus is on reliability and serving customers with the lowest cost
resources. In Washington, energy policy focuses on the Clean Energy Transformation
Act (CETA). This act aims to fundamentally change the trajectory of the adoption of clean ,
non-carbon emitting electric generation by setting a series of targets and changing the
way IRP are developed in Washington State. These requirements change how resource
planning is approached , the modeling techniques and assumptions being used, and
requires the careful consideration of many new issues going well beyond the traditional
utility planning requirement of safety, reliability, and reasonable cost. These three pillars
of resource planning have not gone away and still need to be met along with the new
requirements and aspirations. Some of these new requirements will take several
iterations to plan for them in an efficient manner.
In Washington there are now incentives for clean energy use and development, additional
emphasis on health and equity issues, more diverse participation in the planning process,
and disincentives for greenhouse gas emitting resources. These disincentives include the
end of coal-fired plants serving Washington customers by 2026 and the tapering down
the use of natural gas-fired plants as CET A gets closer to its 100 percent clean energy
goal in 2045.
This chapter discusses the I RP requirements, the process used to develop it, changes
from the 2021 IRP, how resources obtained through 2022 All-Source RFP are included
in the 2023 IRP and concludes with an overview of the chapters and appendices included.
IRP Process
This IRP includes a series of public meetings with a mix of the traditional technical
experts, such as utility commission staff, regional utility professionals, project developers,
advocacy, and environmental groups, concerned state agencies, and both commercial
and residential customers. Table 1.1 lists the dates and topics covered for each of the
Avista Corp 2023 Electric IRP 1-1
Chapter 1: Introduction
public meetings covering assumptions and concepts used in the creation of this IRP. The
meetings include discussions about:
• how the loads are served between now and through 2045 and the resources
already in place to serve those needs,
• the operating and environmental costs and benefits of new resources,
• the costs and benefits of energy efficiency measures and demand response,
• different types of energy storage,
• the expected future and alternate futures, and
• the non-energy impacts of resource decisions.
All these issues combined with the assumptions made about them and how each are
included in the analysis are discussed. The subsequent results of the modeling provide
an expectation of future prices for different resources, energy efficiency, demand
response and storage options can be evaluated against. Avista develops a preferred
portfolio of resources to serve future needs. Besides the technical meetings, there are
also public meetings for customers and others to hear about the plan and provide
comments.
Table 1.1: TAC Meeting Dates and Agenda Items
Meeting Date Agenda Items
TAC 1 -December 8, • TAC Meeting Expectations and IRP Process Review
2021 • 2021 Action Item Review
• Summer 2021 Heat Event -Resource Adequacy and Feeder
Outages
• Northwest Power Pool Resource Adequacy Program
• Resource Adequacy Program Impact to IRP
• IRP resource adequacy/resiliency planning
• TAC Survey Results and Discussion
• Washington State Customer Benefit Indicators
• 2023 Draft IRP Workplan
TAC 2 -February 8, • Process Update
2022 • Demand and Economic Forecast
• Load and Resource Balance Update
TAC 3 -March 9, 2022 • Existing Resource Overview
• Resource Requirements
• Non-Energy Impact Study
• Natural Gas Market Overview and Price Forecast
• Wholesale Electric Price Forecast
TAC 4 -August 10, • Electric Conservation Potential Assessment
2022 • Electric Demand Response Study
• Clean Enerqv Survey
TAC 5 -September 7, • IRP Generation Option Transmission Planning Studies
2022 • Distribution System Planning with the IRP
• Social Cost of Greenhouse Gas for Energy Efficiency -WA Only
• Avoided Cost Rate Methodoloqv
Avista Corp 2023 Electric IRP 1-2
Chapter 1: Introduction
TAC 6 -September 28, • Supply Side Resource Cost Assumptions
2022 • Variable Energy Resource Integration Study Update
• All-Source RPF Update
• Global Climate Change Studies -Impacts to Avista Loads and
Resources
TAC 7 -October 11 , • DER Potential Study Scope
2022 • Load Forecast Update
• Load & Resource Balance -Resource Need
• Natural Gas Market Dynamics
• Wholesale Electric Price Forecast
• Western Resource Adequacy Program Update
• CEIP Update and CBl's Use in the IRP
• Portfolio and Market Scenario Options
Technical Modeling • PRiSM Model Overview
Workshop -October 20, • Risk Assessment Overview
2022 • Washington Use of Electricity Modeling
TAC 8 Washington • Resource Acquisitions
Progress Report • Placeholder Resource Strategy-Energy Efficiency, Demand
Workshop -December Response, Resource Selection and Avoided Cost.
15,2022 • CBI Forecast
• Progress Report Outline
• Next Steps
Virtual Public Meeting -• Recorded Presentation
Natural Gas and Electric • Daytime Comment and Question Session
IRPs -March 8, 2023 • Evening Comment and Question Session
TAC 9 -April 25, 2023 • All-Source RFP Update
• Final Preferred Resource Strategy
• Market Risk Assessment
• Portfolio Scenario Analysis
• Final Report Overview and Comment Plan
• Action Items
Avista greatly appreciates the valuable contributions and time commitments made by
each of its TAC members and wishes to acknowledge and thank the organizations and
members who participated in the development of this IRP. Table 1.2 lists organizations
participating in the 2023 IRP TAC processes.
Avista Corp 2023 Electric IRP 1-3
Chapter 1: Introduction
Table 1.2: External Technical Advisory Committee Participating Organizations
3
AEG
Biomethane, LLC
Bonneville Power Administration Northwest Power and Conservation Council
Buildin lndustr Association of Washin ton Northwest Renewables
Carbon WA
Chelan PUD
Cit of S okane
Clenera
Clear Result
Clearwater Pa er
Climate Solutions
Creative Renewable Solutions
C
D
GE
Heelstone Renewable Ener
Huntwood
Idaho Conservation Lea ue
Idaho Power
Idaho Public Utilities Commission
Inland Power & Light
lnnovari
Kiemle Hagood
McKinstry
Measure Meant
Mitsubishi Power Americas, Inc
MRW Associates
Avista Corp
Pacific NW Utilities Conference Committee
Pera Inc
Phil Jones Consultin
Pivotal Investments
Renewable Northwest
Residential and Small Commercial Customers
Shasta
Sierra Club
Wartsila
Washington State Department of Community,
Trade and Economic Develo ment
Washington State Office of the Attorney
General
Washington State Department of Enterprise
Services
Washington Utilities and Transportation
Commission
Water Planet
2023 Electric IRP 1-4
Chapter 1: Introduction
Washington Progress Report Requirements
This IRP satisfies the Progress Report requirement defined in WAC 480-100-625 and is
due two years after each utility files its IRP. Avista filed its first Progress Report in January
2023, but this IRP is an update to that report. The Progress Report must cover four major
areas plus any necessary updates as identified and described below from WAC 480-100-
625(4 )a -c include:
1. "Load forecast;
2. Demand-side resource assessment including a new conservation potential
assessment;
3. Resource costs; and,
4. The portfolio analysis and preferred portfolio."
Plus any "... other updates that are necessary due to changing state or federal
requirements, or significant changes to economic or market forces." As well as " ... update
for any elements found in the utility's current clean energy implementation plan , as
described in WAC 480-100-640."
Table 1.3: Washington Progress Report Requirement Discussions
Progress Report Requirement IRP Chapter Discussion
Load Forecast Chapter 2 -Economic and Load Forecast
Demand-Side and Conservation Potential Chapter 5 -Distributed Energy Resources
Assessments
Resource Costs Chapter 6 -Supply-Side Resource Options
Portfolio Analysis and Preferred Portfolio Chapter 9 -Preferred Resource Strategy
Chapter 10 -Scenario Analysis
Washington Clean Energy Implementation Plan (CEIP) Coordination
The IRP, in accordance with WAC 480-100-625 (4)(c), updates any elements in the
utility's current CEIP as described in WAC 480-100-640. Avista's 2021 CEIP was
approved with Conditions in June 2022. Avista has included the inputs used and approved
in the development of the 2021 Clean Energy Action Plan (CEAP) filed with the 2021 IRP.
In addition, Conditions agreed to as part of the approval of the 2021 CEIP in Docket UE-
210628 are included in the modeling informing this IRP. The following assumptions were
used to develop the clean energy requirements for 2030 and 2045 CETA requirements.
• Qualifying clean energy is determined by procurement and delivery of clean energy
to Avista's system for all years.
• The clean energy goal is applied to retail sales Jess in-state Public Utility
Regulatory Policies Act (PURPA) generation constructed prior to 2019 plus
voluntary renewable energy programs.
• Customer voluntary Renewable Energy Credits (REC) programs do not qualify
toward the CETA standard.
• Primary and alternative compliance generation includes:
Avista Corp 2023 Electric IRP 1-5
Chapter 1: Introduction
o Washington's share of legacy hydro generation operating or contracted with
deliveries before 2022,
o All wind, solar, and biomass generation. Nonpower attributes associated
with Idaho's share may be purchased by Washington,
o Newly acquired or contracted non-emitting generation including hydro,
wind, solar, or biomass.
• Avista may transfer qualifying non-hydro clean energy generated for Idaho loads
to Washington by compensating Idaho at market REC prices.
• Avista is not planning to use Idaho's share of existing hydro prior to 2030 for
compliance . After 2030, these resources are planned to be available for Alternative
Compliance.
Conditions For IRP Progress Report from CEIP
Several of the Washington Utilities and Transportation Commission's (WUTC) approved
conditions for the Company's CEIP were required to be included in the Progress Report.
The following six conditions, listed by their original number issued in Order 01 from the
WUTC, are covered in the Progress Report.
(2) Avista will apply Non-Energy Impacts (NEis) and Customer Benefit Indicators (CBls)
to all resource and program selections in determining its Washington resource strategy,
in its 2023 !RP/Progress Report and will incorporate any guidance given by the
Commission on how to best utilize CBls in CEIP planning and evaluation. Avista agrees
to engage and consult with its applicable advisory groups (IRP Technical Advisory
Committee (TAC) and Energy Efficiency Advisory Group (EEAG)) regarding an
appropriate methodology for including NEis and CBls in its resource selection. (Per Order
01 : Avista will consult with its Equity Advisory Group (EAG) after the development of this
methodology to ensure the methodology does not result in inequitable results.)
Avista discussed with the TAC and EEAG on Oct 11, 2022 its approach to
using both NE/ and CB/s with the progress report, The EAG was also
consulted during its meetings held on November 16th and 18th, 2022.
Members did not voice concerns pertaining to inequities in the Company's
approach.
(8) Avista in its IRP resource selection model for the 2023 IRP Progress Report will give
the model the option to meet Clean Energy Transformation Act (CET A) goals with a
choice between an Idaho allocated existing renewable resource at market price (limited
to Kettle Falls, Palouse Wind, Rattlesnake Flat, Chelan PUD purchase contracts 2 & 3)
or acquiring a new 100% allocated Washington renewable resource for primary
compliance. Further, the model will have the option to acquire new 100% allocated
resource, market REC, or Idaho allocated REC (at market prices) to meet alternative
compliance.
Avista Corp 2023 Electric IRP 1-6
Chapter 1: Introduction
A vista included logic in the PRiSM model to choose how it solves to meet
primary and alternative compliance requirements either by using existing
resources or by acquiring new resources.
(14) Avista will include a Distributed Energy Resources (DERs) potential assessment for
each distribution feeder no later than its 2025 electric IRP. Avista will develop a scope of
work for this project no later than the end of 2022, including input from the IRP TAC,
EEAG, and Distribution Planning Advisory Group (DPAG). The assessment will include a
low-income DER potential assessment. Avista will document its DER potential
assessment work in the Company's 2023 IRP Progress Report in the form of a project
plan, including project schedule, interim milestones, and explanations of how these efforts
address WAC 480-100-620(3)(b)(iii) and (iv).
The potential assessment for this study was discussed at both the TAC and
EEAG meetings in October 2022, the project plan and schedule is described
in Chapter 5 and the proposed scope of work is in Appendix G.
(34) For its 2023 IRP Progress Report, Avista commits to reevaluate its resource need
given acquisitions the Company has made since its 2021 IRP (e.g., Chelan PUD hydro
slice contracts) and include those proposed changes in its 2023 Biennial Clean Energy
Implementation Plan (CEIP) Update.
A vista has included within its resource energy need all long-term resources
currently under contract including the Chelan PUD slice agreements and
the Columbia Basin Hydro agreement. Further, it includes planned
upgrades to both Kettle Falls and Post Falls as well as the extension of the
existing Lancaster Purchase Power Agreement (PPA).
(35) Avista recognizes that not all CBls will be relevant to resource selection (for example,
some CBls pertain to program implementation). For its 2023 IRP Progress Report, and
future IRPs and progress reports, Avista should discuss each CBI and where the CBI is
not relevant to resource selection, explain why.
Chapter 11 outlines how each CBI is relevant or not to resource selection
or studied within the resource planning process. For those CBls with a
relation to resource selection, a forecast of their impact on the plan is
included.
(36) For its 2023 IRP Progress Report, Avista will:
A. At the September 28, 2022, Electric IRP TAC meeting, present draft supply side
resource cost assumptions, including DERs. The Company commits to revising
said cost assumptions if TAC stakeholder feedback warrants changes. Avista will
Avista Corp 2023 Electric IRP 1-7
Chapter 1: Introduction
update its 2023 Electric IRP Work Plan (UE-200301) to reflect the date of this TAC
meeting.
B. Use the Qualifying Capacity Credit (QCC) for renewable and storage resources
from the Western Power Pool's Western (WPP) Regional Adequacy Program
(WRAP), if available, or explain why the WRAP's QCCs are inappropriate for use.
C. Update its load forecast to include the baseline zero emission vehicles (ZEV)
scenario from its Transportation Electrification Plan .
Avista presented and provided TAC members with a complete supply
resource assumptions at the September 2022 meeting. The resource
assumptions are discussed in Chapter 6 of this Progress Report, along with
associated technical documentation in Appendix F. Avista also uses QCC
values where applicable from the WRAP, these are discussed in Chapter 3
for existing resources, Chapter 5 for DERs, and Chapter 6 for utility scale
resources. Within Chapter 2 is a discussion of the associated loads included
using the Transportation Electrification Plan.
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 [(RMR)]". This report recognize[s]
the managerial aspects of owning and maintaining existing resources as well as procuring
new resources and avoiding/reducing load. [The Commission 's] desire is the report on
the utility's planning status, not a requirement to implement new planning efforts
according to some bureaucratic dictum. We realize that integrated resource planning is
an ongoing, changing process. Thus, we consider the RMR required herein to be similar
to an accounting balance sheet, i.e., a "freeze-frame" look at a utility's fluid process.
The report should discuss any flexibilities and analyses considered during comprehensive
resource planning such as:
1. Examination of load forecast uncertainties
2. Effects of known or potential changes to existing resources
3. Consideration of demand-and supply-side resource options
4. Contingencies for upgrading, optioning and acquiring resources at optimum times
(considering cost, availability, lead-time, reliability, risk, etc.) as future events
unfold.
Avista outlines the order's requirements below for ease of readability for each of the
Commission's requirements.
Avista Corp 2023 Electric IRP 1-8
Chapter 1: Introduction
Existing Resource Stack
Identification of all resources by category below;1 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 appendix:2
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;
1 Resources less than three megawatts should be grouped as a single resource in the appropriate category.
2 FERC Form 714 can be on-line at https://www.ferc.gov/docs-filing/forms/form-714/data.asp
Avista Corp 2023 Electric IRP 1-9
Chapter 1: Introduction
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;
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
Avista Corp 2023 Electric IRP 1-10
Chapter 1: Introduction
understanding of the utility's expected responses over the full range of possible
future conditions.
• The guidance provided above is intended to ensure maximum flexibility to utilities
in presenting their resource plans. Ideally, each utility will use several scenarios to
demonstrate potential maximum, minimum and intermediate levels of new
resource requirements and the expected means of fulfilling those requirements.
For example,
o A credible scenario requiring maximum new resources might be regional
load growth exceeding 3% per year combined with catastrophic destruction
(earthquake, fire, flood, etc.) of a utility's largest resource (i.e., Bridger coal
plant for IPCo and PP&L, Hunter coal plant for UP&L and Noxon hydro plant
forWWP).
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,
Avista Corp
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
2023 Electric IRP 1-11
Chapter 1: Introduction
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
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.
Avista Corp 2023 Electric IRP 1-12
Chapter 1: Introduction
• 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.
Summary of Changes from the 2021 IRP
Avista made several material changes to the methodology of the analysis since the 2021
IRP. The major changes are the capacity and energy position methodology, updated
energy efficiency and demand response potentials, updates to supply-side resource
options and costs, refreshed wholesale market analysis and additional methods for the
portfolio optimization analysis, each are described below.
Capacity and Energy Position, Including Load Forecasting
• The WPP's WRAP methodology is used for capacity planning . Avista will not use
the WRAP planning reserve margin for planning until the program is binding but
will utilize the QCC methodology (for early years only) and accounting metrics.
• The energy risk metric for energy planning now includes risks from load , hydro,
and Variable Energy Resources (VERs), prior plans did not include VERs within
the calculation.
• Load and hydro forecasts use the Representative Concentration Pathway (RCP)
4.53 temperature forecast for future years rather than historical averages.
• A forecast for medium duty electric vehicles is included in the electric load forecast
and the light duty vehicle forecast matches the Company's Transportation
Electrification Plan.
• Recent resource acquisitions are included in this forecast from Chelan PUD,
Columbia Basin Hydro, a 30-year wind PPA, the extension of the Lancaster PPA,
and upgrades to Kettle Falls and Post Falls.
Energy Efficiency and Demand Response
• NEis are included on an individual measure basis rather than a single value for all
programs for Washington programs.
3 RCP 4.5 is defined in Chapter 4.
Avista Corp 2023 Electric IRP 1-13
Chapter 1: Introduction
• The Named Community Investment Fund (NCIF) sets a threshold for additional
low-income energy efficiency targets beyond cost effective measures for
Washington.
• Peak time rebate and electric vehicle time of use are added to the list of demand
response options.
Supply-Side Resource Options
• Resource options include new distribution level storage resource options including
roof-top solar, community solar, and customer owned storage.
• New energy storage options include iron-oxide storage and renewable fueled
(ammonia) turbines.
• The Inflation Reduction Act tax incentives are reflected in resource cost.
• An NEI study for new resources is reflected in the resource selection for
Washington resources.
• WRAP QCCs are used for new resource selection but discounted over time4 to
reflect changes in regional generation mix.
Market Analysis
• A new regional resource forecast is updated to reflect best available information
utilizing Energy Exemplar's latest Western Electricity Coordinating Council
(WECC) database.
• The Climate Commitment Act (CCA) is reflected in the market forecast using
Ecology's price estimate for imported power and power plants without free
allowances.
• The stochastic price forecast was reduced from 500 hourly 8760-hour simulations
to 300 hourly simulations due to enhanced modeling logic for storage resources
increasing run times.
Portfolio Optimization Analysis
• Monthly level energy positions rather than annual are used and includes a
constraint to satisfy all monthly energy positions with resources capable of delivery
energy in each period.
• Monthly level capacity positions rather than summer and winter peak positions are
used for solved resource needs.
• Avista assumes CETA compliance on a monthly level where controlled renewables
will count towards primary compliance if generated within the month up to the
monthly retail load. Any renewable generation greater than monthly retail load is
assumed to count toward alternative compliance.
• Applicable CBI results are included within the PRiSM model for Washington.
• The NCIF creates thresholds distributed energy resources to address state policy
choices.
4 For wind, solar, energy storage and demand response.
Avista Corp 2023 Electric IRP 1-14
Chapter 1: Introduction
Modeling and Assumption Updates to January 2023 Progress Report Filing
1. Reflect all resource acquisitions from the 2022 All-Source RFP.
2. Update the load forecast due to changing requirements for natural gas usage in
new residential buildings in Washington.
3. Include any available information regarding the functionality of Washington's CCA.
4. Include stakeholder feedback for improvement in the analysis or the report.
5. Include portfolio scenario analysis and market risk impacts on scenarios.
2023 IRP Chapter Outline
The 2023 IRP consists of 12 chapters.
Chapter 1: Introduction, Stakeholder Involvement and Process Changes
This chapter introduces the IRP, covers requirements and details public participation and
involvement in the process used to develop it, as well as significant assumption, modeling
and process changes between the 2021 and 2023 IRPs.
Chapter 2: Economic and Load Forecast
This chapter covers regional economic conditions, Avista's energy and the peak load
forecasts, including scenarios with different load projections.
Chapter 3: Existing Supply Resources
This chapter provides an overview of Avista-owned generating resources and its
contractual resources and obligations and environmental considerations .
Chapter 4: Long-Term Position
This chapter reviews Avista reliability planning and reserve margins, risk planning,
resource requirements and provides an assessment of its reserves and resource
flexibility. This chapter also covers the RCP 4.5 temperature and hydrology forecast.
Chapter 5: Distributed Energy Resources
This chapter discusses customer focused resources such as energy efficiency programs,
demand response and distributed generation and energy storage. It provides an overview
of the conservation and demand response potential assessments , and customer owned
or other distributed generation resources.
Chapter 6: Supply-Side Resource Options
This chapter covers the cost and operating characteristics of utility scale supply side
resource options modeled for the IRP.
Chapter 7: Transmission Planning & Distribution
This chapter discusses Avista distribution and transmission systems, as well as regional
transmission planning issues. It includes details on transmission cost studies used in IRP
Avista Corp 2023 Electric IRP 1-15
Chapter 1: Introduction
modeling and summarizes Avista's 10-year Transmission Plan . The chapter concludes
with a discussion of distribution planning , including storage benefits to the distribution
system.
Chapter 8: Market Analysis
This chapter details Avista IRP modeling and its analyses of the wholesale electric and
natural gas markets.
Chapter 9: Preferred Resource Strategy
This chapter details the Preferred Resource Strategy (PRS) selection process used to
develop the 2023 PRS and resulting avoided costs.
Chapter 10: Scenario Analysis
This chapter presents alternative resource portfolios and shows how each scenario
performs under different energy market conditions.
Chapter 11: Customer Impacts
This chapter includes an assessment of energy and nonenergy benefits and reductions
of burdens to vulnerable populations and highly impacted communities; long-and short­
term public health and environmental benefits, costs, and risks; and energy security risk.
It also covers the inclusion of metrics related to NEis and CBls where applicable as well
as which ones are quantifiable and included in resource modeling. It also estimates the
degree to which benefits will be equitably distributed and/or burdened over the planning
horizon.
Chapter 12: Action Plan
This chapter discusses progress made on Action Items in the 2021 IRP. It details the
areas Avista will focus on between publication of this plan and the 2025 IRP.
2023 IRP Appendices
Appendix A: TAC Presentations
This appendix includes the presentations for the nine TAC meetings and meeting notes
plus the public presentations.
Appendix B: IRP Work Plan
This appendix includes 2023 IRP Work Plan outlining the process Avista's used to
develop its 2023 Electric IRP for filing with the Washington and Idaho Commissions by
June 1, 2023.
Avista Corp 2023 Electric IRP 1-16
Chapter 1: Introduction
Appendix C: AEG Conservation and Demand Response Potential Assessments
This appendix includes the conservation (energy efficiency) and demand response
potential assessment studies.
Appendix D: DNV Non-Energy Impact Studies
This appendix includes NEI Studies from DNV for supply-side and energy efficiency
resources.
Appendix E: Transmission Designated Network Study
This appendix includes the transmission study results for this IRP.
Appendix F: Inputs and Results
This appendix includes all the IRP data assumptions, such as cost and operating
characteristics for generic resource types, as well as the modeling results.
Appendix G: Distributed Energy Resources Scope of Work
This appendix includes the scope of work for the upcoming study of feeder level potential
of distributed energy resources for the Washington service territory.
Appendix H: Confidential Historical Generation Operation Data
This appendix includes actual monthly data for PURPA generation and forced outage
data for Avista's resources.
Appendix I: New Resource Table for Transmission
This appendix approximates the location of new resources for transmission planning .
Appendix J: Confidential Inputs and Models
This appendix including the Aurora model and ARAM models.
Appendix K: Resource Portfolio Summary
This appendix includes the resources selected by year for each of the portfolio scenarios
discussed in Chapter 10.
Appendix L: Public Comments
This appendix includes written comments from the public and advisory group members.
Avista Corp 2023 Electric IRP 1-17
Chapter 1: Introduction
This Page is Intentionally Left Blank
Avista Corp 2023 Electric IRP 1-18
Chapter 2: Economic & Load Forecast
2. Economic & Load Forecast
Avista's loads and resources are an integral component of the Integrated Resource Plan
(IRP). This chapter summarizes customer and load projections; including adjustments to
assumptions for customer-owned solar generation, electric vehicles, natural gas
restrictions, and changing temperatures, as well as recent enhancements to load and
customer forecasting models and processes.
Chapter Highlights
• The energy forecast grows 0.85% per year, higher than the 0.24% annual
growth rate in the 2021 IRP. Higher growth largely reflects higher residential
and commercial electric vehicles (EV) forecasts and new building
electrification.
• Avista expects a 146 aMW increase in total load from residential and
commercial EVs and a net decrease of 21 aMW from residential and
commercial solar by 2045.
• Peak load growth is 1.16% in the winter and 1.24% in the summer.
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, Washington MSA (Spokane­
Stevens counties); the Coeur d'Alene, Idaho MSA (Kootenai County); and the Lewiston­
Clarkson Idaho-Washington, MSA (Nez Perce-Asotin counties). These three MSAs
account for over 70% of both Avista's customers (i.e., meters) and load. The remaining
30% are in low-density rural areas in both states. Washington accounts for approximately
two-thirds of customers and Idaho the remaining one-third.
Population
Population growth is increasingly a result of net migration within Avista 's service area as
more people move here. Net migration is strongly associated with both service area and
national employment growth through the business cycle. The regional business cycle
follows the U.S. business cycle, meaning regional economic expansions or contractions
follow national trends.1 Econometric analysis shows when regional employment growth
is stronger than U.S. growth over the business cycle, it is associated with increased in­
migration and the reverse holds true. Figure 2.1 shows annual population growth since
1971 and highlights the recessions in yellow. During all deep economic downturns since
the mid-1970s, reduced population growth rates in Avista's service territory led to lower
load growth.2 The Great Recession reduced population growth from nearly 2% in 2007 to
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.
Avista Corp 2023 Electric IRP 2-1
Chapter 2: Economic & Load Forecast
less than 1% from 2010 to 2013. Accelerating service area employment growth in 2013
helped push population growth above 1% after 2014.
Figure 2.1: MSA Population Growth and U.S. Recessions, 1971-2021
Figure 2.2 shows population growth since 2012.3 Service area population growth over the
2010-2012 period was weaker than the U.S.; however, it was closely associated with the
strength of regional employment growth relative to the U.S. over the same period. The
same can be said for the increase in service area population growth in 2014 relative to
the U.S. population growth. The association of employment growth to population growth
has a one-year lag. The relative strength of service area employment growth in year "y"
is positively associated with service area population growth in year "y+1 ". Econometric
estimates using historical data show when holding the U.S. employment-growth constant,
every 1 % increase in service area employment growth is associated with a 0.4% increase
in population growth in the next year.
3 Data Source: Bureau of Economic Analysis, U.S. Census, and Washington State Office of Financial
Management.
Avista Corp 2023 Electric IRP 2-2
Chapter 2: Economic & Load Forecast
Figure 2.2: Avista and U.S. MSA Population Growth, 2012-2021
■Avista WA-ID MSAs ■U.S.
2012 201 3 2014 2015 2016 2017 2018 2019 2020 2021
Employment
Given the correlation between population and employment growth, it is useful to examine
the distribution of employment and employment performance since 2012. The Inland
Northwest is a services-based economy rather than its former natural resources-based
manufacturing economy. Figure 2.3 shows the breakdown of non-farm employment for
all three-service area MSAs from the Bureau of Labor and Statistics. Almost 70% of
employment in the three MSAs is in private services, followed by government (16%) and
private goods-producing sectors (14%). Farming accounts for 1 % of total employment.
Spokane and Coeur d'Alene MSAs are major providers of health and higher education
services to the Inland Northwest.
Figure 2.3: MSA Non-Farm Employment Breakdown by Major Sector, 2021
Avista Corp
Local Government,
11%
State Government, "'\
3% \
Federal
Government, 2%
2023 Electric IRP 2-3
Chapter 2: Economic & Load Forecast
Following the Great Recession, regional employment recovery did not materialize until
2013, when services employment started to grow.4 Service area employment growth
began to match or exceed U.S. growth rates by the fourth quarter 2014. Since the COVID-
19 induced recession in 2020, service area employment has more than recovered from
the losses resulting from the nationwide shutdowns. Figure 2.4 compares Avista and the
U.S MSA non-farm employment growth for 2012 to 2021.
Figure 2.4: Avista and U.S. MSA Non-Farm Employment Growth, 2012-2021
■Avista WA-ID MSAs ■U.S.
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Figure 2.5 shows the distribution of personal income, a broad measure of both earned
income and transfer payments, for A vista's Washington and Idaho MSAs. 5 Regular
income includes net earnings from employment, and investment income in the form of
dividends, interest, and rent. Personal current transfer payments include money income
and in-kind transfers received through unemployment benefits, low-income food
assistance, Social Security, Medicare, and Medicaid.
Transfer payments in Avista's service area in 1970 accounted for 12% of the local
economy. The income share of transfer payments has nearly doubled over the last 40
years to 27%. Although 56% of personal income is from net earnings, transfer payments
still account for more than one in every five dollars of personal income. Recent years
have seen transfer payments become the fastest growing component of regional personal
income. This growth in regional transfer payments reflects an aging regional population,
a surge of military veterans, and the lingering impacts of the COVID transfer payments to
households, including enhanced unemployment benefits.
4 Data Source: Bureau of Labor and Statistics.
5 Data Source: Bureau of Economic Analysis.
Avista Corp 2023 Electric IRP 2-4
Chapter 2: Economic & Load Forecast
Figure 2.6 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 according to the Bureau of
Economic Analysis. The impacts of these recessions were more negative in the service
area compared to the U.S., so the ratio of service area per capita income to U.S. per
capita income fell from 93% in the 1970s to around 85% by the mid-1990s. The income
ratio has not recovered.
Figure 2.5: MSA Personal Income Breakdown by Major Source, 2021
Transfer
Receipts, 27%
Dividends,
Interest, and
Rent, 17%
Figure 2.6: Avista and U.S. MSA Real Personal Income Growth by Decade, 1970-2021
3.0%
2.5%
2.0%
1.5%
1.0%
0.5%
0.0%
1970 to 1980
Avista Corp
1980 to 1990 1990 to 2000
2023 Electric IRP
■Avista WA-ID MSAs
■U.S.
2000to2010 2010to2021
2-5
Chapter 2: Economic & Load Forecast
Overview of the Medium-Term Retail Load Forecast
The retail load forecast is a two-step process. The first step is a detailed medium-term
forecast to 2026. The second step bootstraps off the medium-term forecast to generate
a forecast for years 2027 to 2045 by applying the long-run growth assumptions discussed
later in this chapter.
There is a monthly use per customer (UPC) forecast and a monthly customer forecast for
each customer class in most rate schedules.6 The load forecast multiplies the customer
and UPC forecasts. The UPC and customer forecasts are generated using time-series
econometrics, as shown in Equation 2.1 .
Equation 2.1: Generating Schedule Total Load
F(kWht,Yc+j,s) = F(kWh/Ct,Yc+j,s) X F(Ct,Yc+j,s)
Where:
• F(kWht,yc+i,s) = the forecast for month t, year j = 1, ... ,5 beyond the
current year, ye ,for schedule s.
• F(kWh/Ct,yc+i,s) = the UPC forecast.
• F(Ct,yc+i,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:7
Equation 2.2: Use Per Customer Regression Equation
kWh/Ct,y,s = aWt,y + f3Zt,y + Et,y
The model uses actual historical weather, UPC and non-weather drivers to estimate the
regression in Equation 2.2. To develop the forecast, normal weather replaces actual
weather (W) along with the forecasted values for the Z variables (Faruqui, pp. 6-7). Here,
Wis a vector of heating degree day (HOD) and cooling degree day (COD) variables; Z is
a vector of non-weather variables; and Et,y is an uncorrelated N(0,cr) error term. For non­
weather sensitive schedules, W = 0.
The W variables will be HDDs and CDDs. Depending on the rate 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
6 For schedules representing a single customer, where there is no customer count and for street lighting,
Avista forecasts total load directly without first forecasting UPC.
7 Faruqui, Ahmad (2000). Making Forecasts and Weather Normalization Work Together, Electric Power
Research Institute, Publication No. 1000546, Tech Review, March 2000.
Avista Corp 2023 Electric IRP 2-6
Chapter 2: Economic & Load Forecast
Index (CPI), less energy. For most schedules, the only non-weather variables are SD ,
SC, and OL. See Table 2.1 for the occurrence RAP and IP.
If the error term appears to be non-white noise, then the forecasting performance of
Equation 2.2 can be improved by converting it into an (ARIMA) "transfer function" model
such that €1,y = ARIMA€t,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 (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 rate schedules, such as lighting, use simpler regression and smoothing methods
because they offer the best fit for irregular usage without seasonal or weather-related
behavior, are in a long-run steady decline, or are seasonal and unrelated to weather.
Over the 2023-2026 period , Avista defines normal weather for the load forecast as a 20-
year moving average of degree-days taken from the National Oceanic and Atmospheric
Administration's Spokane International Airport data. Normal weather updates only occur
when a full year of new data is available. For example, normal weather for 2018 is the 20-
year average of degree-days for the 1998 to 2017 period; and 2019 is the average of the
1999 to 2018 period. This forecast uses the 20-year average from the 2002 to 2021 period
to develop the 2023 to 2026 forecast.
The choice of a 20-year moving average for defining normal weather reflects several
factors. First, climate research from the National Aeronautics and Space Administration's
(NASA) Goddard Institute for Space Studies (GISS) shows a shift in temperature starting
almost 30 years ago. The GISS research finds summer temperatures in the Northern
Hemisphere increased one degree Fahrenheit above the 1951-1980 reference period;
the increase started roughly 30 years ago in the 1981-1991 period.8 An in-house analysis
of temperature in Avista's Spokane-Kootenai service area, using the same 1951-1980
reference period, also showed an upward shift in temperature starting about 30-years
ago. A detailed discussion of this analysis is provided in the peak-load forecast section of
this chapter.
The second factor in using a 20-year moving average is the volatility of the moving
average as a function of the years used to calculate the average. The 10-and 15-year
moving averages showed considerably more year-to-year volatility than the 20-year
moving average. This volatility can obscure longer-term trends and leads to overly sharp
changes in forecasted loads when applying the updated definition of normal weather each
year. These sharp changes would also cause excessive volatility in the revenue and
earnings forecasts .
As will be discussed below and in Chapter 4, the temperature is assumed to increase
after 2026 based on temperature modeling from an ensemble of global climate models
analyzed as part of the Columbia River Management Joint Operating Committee
8 See Hansen, J.; M. Sato; and R. Ruedy (2013). Global Temperature Update Through 2012,
http://www.nasa.gov/topics/earth/features/2012-temps. htm I.
Avista Corp 2023 Electric IRP 2-7
Chapter 2: Economic & Load Forecast
(RMJOC) II Climate Change Analysis using the Relative Concentration Pathway (RCP)
4.5 forecast. In other words , the 20-year moving average of weather is used until 2026.
Starting in 2027, changing HDDs and CDDs are built in using the RMJOC II RCP 4.5
forecast. The forecast predicts a steady decline in HDDs and increase in CDDs over the
2027-2045 period.
As noted earlier, if non-weather drivers appear in Equation 2.2, then they must also be in
the five-year forecast used to generate the UPC forecast. The assumption in the five-year
forecast is for RAP to be constant through 2027; increase at 1 % from 2027 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, this forecast assumes residential and
commercial own-price elasticity to be -0.3%, based on long-run estimates from academic
literature.9 This forecast generates IP forecasts from a regression using the GDP growth
forecasts (GGDP). Figure 2.7 describes this process.
Table 2.1: UPC Models Using Non-Weather Driver Variables
Schedule Variables Comment
Washington:
Residential Schedule 1 GAS Ratio of natural gas residential schedule 101
customers in WA to electric residential schedule
1 customers in WA.
Industrial Schedules 11 , 21 , and 25 IP
Idaho:
Residential Schedule 1 GAS Ratio of natural gas residential schedule 101
customers in ID to electric residential schedule
1 customers in ID.
Industrial Schedules 11 and 21 IP
The forecasts for GDP reflect the average of forecasts from multiple sources including
the Bloomberg survey of forecasts, the Philadelphia Federal Reserve survey of
forecasters , the Wall Street Journal survey of forecasters and other sources. Averaging
forecasts reduces the systematic errors of a single-source forecast and assumes
macroeconomic factors flow through the UPC in the industrial rate schedules. This
reflects the relative stability of industrial customer growth over the business cycle. Figure
2.8 shows the historical relationship between the IP and industrial load for electricity.10·11
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.
9 Avista is unable to produce reliable elasticity estimates using its own UPC data. It is difficult to obtain
reliable elasticity estimates using data for an individual utility, so the Company relies on academic estimates
using multiple regions and estimation methods. As theory predicts, the literature indicates that short-term
elasticity is lower (less price sensitive) than long-term elasticity. Avista assumes the low end of the long­
term range of academic elasticity estimates.
10 Data Source: U.S. Federal Reserve and Avista records.
11 Figure 2.8 excludes one large industrial customer with significant load volatility.
Avista Corp 2023 Electric IRP 2-8
Chapter 2: Economic & Load Forecast
Figure 2.7: Forecasting IP Growth
Average GDP U.S Industrial Production Generate Average, High, and Low
IP Forecast: Growth Forecasts: Index (IP) Growth Model: Forecast annual IP growth •
•
't:I Ill 0 ...I
IMF, FOMC, Model links year y • •
Bloomberg, etc. ~ GDP growth year y IP ~ using the GDP forecast
Average growth. average (the baseline
scenario), a "high" scenario, forecasts out 5-• Federal Reserve and a "low" scenario. yrs. industrial production The high and low GDP index is measure of IP •
growth . forecasts are the annual high
and low values from the • Forecast out 5-years . 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.
Figure 2.8: Industrial Load and Industrial (IP) Index
130GWh .---------------------------------, 130
120 GWh
110GWh
100 GWh
90GWh
80GWh
70GWh
1--------------------------~-------j 120 4i'°
C:
::::i
41 :::, i-----.---------------------,------~'llt-1l\hi,....--nrt 110 ii5 -
--Industrial, SA ---Industrial, Trend-Cycle --Industrial Production
Customer Forecast Methodology
The econometric modeling for the customer models ranges from simple smoothing
models to more complex ARIMA models. In some cases, a pure ARIMA model without
any structural independent variables is used. For example, the independent variables are
only the past values of the rate schedule customer counts, which is also the dependent
variable. Because the customer counts in most rate schedules are either flat or growing
in a stable fashion, complex econometric models are generally unnecessary for
Avista Corp 2023 Electric IRP 2-9
Chapter 2: Economic & Load Forecast
generating reliable forecasts. Only in the case of certain residential and commercial
schedules is more complex modeling required.
For the main residential and commercial rate schedules, the modeling approach needs
to account for customer growth between these schedules with a high positive correlation
over a 12-month period. This high customer correlation translates into a high correlation
over the same 12-month period. Table 2.2 shows the correlation of customer growth
between residential, commercial, and industrial consumers of Avista's 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.
Table 2.2: Customer Growth Correlations, 1998 -2021
Customer Class Residential Commercial Industrial Streetlights
(Annual growth)
Residential 1.00
Commercial 0.74 1.00
Industrial -0.26 -0.0004 1.00
Streetliqhts -0.21 -0.07 -0.02 1.00
Figure 2.9 shows the relationship between annual population growth and year-over-year
customer growth.12 Customer growth has closely followed population growth in the
combined Spokane-Kootenai MSAs over the last 20 years. Population growth averaged
1.3% over the 2000-2021 period and customer growth averaged 1.3% annually.
Figure 2.9 demonstrates how population growth is the primary driver of customer growth.
As a result, forecasted population growth is the primary driver of Residential Schedule 1
customers in Washington and Idaho. The forecast is made using an ARIMA times-series
model for Schedule 1 customers in Washington and Idaho.
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.
12 Data Source: Bureau of Economic Analysis, U.S. Census, Washington State OFM, and Avista records.
Avista Corp 2023 Electric IRP 2-10
Chapter 2: Economic & Load Forecast
Figure 2.9: Population Growth vs. Customer Growth, 2000-2021
2.5%
2.0%
1.5%
1.0% -
0.5%
0.0%
N 8 N
r
"' 0 0 N
r
V 8 N
l() 0 0 N
r
co
8 N
r---0 0 N
r
co
8 N
,_
l 7
O> 0
8 0 N N
■Avista WA-ID MSAs
System Customers
.., --
7 ,_
~
N "' V l() co r---co O> 0 0 0 0 0 0 0 0 0 ~ N N N N N N N N N
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 HIS Global Insight) forecasts for the same counties. Averaging
reduces the systematic errors of a single-source forecast. The averaged employment
forecasts become inputs to generate population growth forecasts. Figure 2.10
summarizes the forecasting process for population growth for use in estimating
Residential Schedule 1 customers.
Figure 2.10: Forecasting Population Growth
Average GDP Regional Population Growth Models:
Growth Forecasts: • Model links regional, U.S., and CA year y-1
• IMF, FOMC, employment growth to year y county
Bloomberg, etc. Non-farm Employment population growth.
• Average Growth Model: • Forecast out 5-years for Spokane, WA and
forecasts out 5-• Model links year y, y-Kootenai, ID.
years. 1, and y-2 GDP • Averaged with IHS forecasts in ID and WA.
growth to year y • Growth rates used to generate population
I regional employment forecasts for customer forecasts for
growth. residential schedule 1.
GDP II • Forecast out 5-
years. t • Averaged with IHS EMP forecasts.
The employment growth forecasts (average of Avista and IHS forecasts) become inputs
used to generate the population growth forecasts. The Spokane and Kootenai forecast
are averaged with IHS's forecasts 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.
Avista Corp 2023 Electric IRP 2-11
Chapter 2: Economic & Load Forecast
Long-Term Load Forecast
The Basic Model
The long-term load forecast extends the intermediate term projection out to 2045. It
includes adjustments for electric vehicle (EV) fleet and residential rooftop photovoltaic
(PV) solar growth. The long-run modeling approach starts with Equation 2.3.
Where:
Equation 2.3: Long-Run Forecast Relationship
fy =Cy+ Uy
• fy = class load growth in year y.
• Cy = class customer growth in year y.
• Uy = class UPC growth in year y.
Equation 2.3 sets annual residential load growth equal to annual customer growth plus
the annual UPC growth.13 Cy is not dependent on weather, so where Uy values are
weather normalized, f y results are weather-normalized. Varying Cy and Uy generates
different long-term forecast simulations. This forecast varies Cy for economic reasons and
Uy for increased usage of PVs, EVs, and expected policy changes.
Expected Case Assumptions
The forecast makes the following assumptions about the long-run relationship between
residential, commercial, and industrial classes.
1. Load Growth by Revenue Class
As noted earlier, long-term residential and commercial customer growth rates are
linked, with a positive correlation between the two (see Table 2.2). Figure 2.11 shows
the time path of residential customer growth. The average annual growth rate from
2023 to 2045 is approximately 0.9%, with a gradual decline out to 2045. The growth
rates to 2026 shown in Figure 2.11 uses Avista's own employment and population
forecasts in conjunction with IHS's employment and population forecasts. After 2026,
IHS's population forecasts alone drive the residential customer forecast. Starting in
2027, the model assumes annual commercial customers increase by approximately
11 customers for every 100 additional residential customers. This relationship is based
on long-run annual regression relationships. The annual average growth rate of
commercial customers over 2023-2045 is approximately 0.6%. Average annual
industrial customer growth rate over 2023-2045 is -1.0%, which is equivalent to an
annual decline of 11 industrial customers a year through 2045. This assumption
reflects an ongoing long-term decline in industrial customers since 2005.
2. Flat Streetlight Growth
Consistent with historical behavior, industrial and streetlight load growth projections
do not correlate with residential or commercial load. Average annual industrial load
13 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.
Avista Corp 2023 Electric IRP 2-12
Chapter 2: Economic & Load Forecast
growth is -0.3% over the forecast horizon. This reflects the assumption that the annual
-1 .0% decline in industrial customer growth is not offset by UPC growth driven by long­
run economic growth, as measured by GDP growth . The GDP growth assumption
averages 1.8% after 2026, which is the long-run growth used by the Federal Reserve
for their forward guidance. The streetlight load growth is 0% over the forecast horizon
to reflect the assumption of slow customer growth being offset by the impact of LED
lighting.
3. Real Average Energy Price Annual Increase
As noted earlier, the assumption in the five-year forecast is for the RAP for residential
and commercial load to be constant through 2026; increase 1 % annually between
2026 and 2029; and then increase 1.5% yearly until 2045. RAP no longer appears
explicitly in the regression equations for the medium-term forecast. The regression
coefficient estimates for the RAP have become unstable and statistically insignificant.
Therefore, the forecast assumes own-price elasticity to be -0.3%, based on long-term
estimates from the academic literature (See also footnote 11 ).
Figure 2.11: Long-Term Annual Residential Customer Growth
V ~ ID ~ 00 m O N M V ~ ID ~ ~ m O N M V ~ N N N N N N M M M M M M M M M M V V V V V V 0 D O O O O O O O O O O O O O O O O O O O 0 N N N N N N N N N N N N N N N N N N N N N N
4. Electric Vehicles Growth Rates Increase
Avista estimates approximately 3,900 residential light duty electric vehicles (LDEV)
are currently within its service area. The forecasted rate of EV adoption over the 2023-
2045 period assumes 342,000 LDEVs will be in the service area by 2045. This is an
average annual growth rate of 23% between 2024 and 2045. To be consistent with
Avista's current Transportation Electrification Plan, the forecast assumes each LDEV
averages 3,153 kWh per year and will constitute 15% of all residential light-duty
vehicle sales by 2030 and 38% by 2045. Based on the assumption of approximately
two vehicles per residential customer (based on U.S. Census data for Avista's service
Avista Corp 2023 Electric IRP 2-13
Chapter 2: Economic & Load Forecast
area), the LDEV penetration rate is forecasted to rise from 0.5% of residential
customers in 2023 to just over 27% by 2045 for a total load of 123 aMW in 2045.
Avista estimates there are approximately 160 commercial medium duty electric
vehicles (MDEV) currently operating in its service area. The forecasted rate of
adoption over the 2024-2045 period assumes 25,000 MDEVs will be in the service
area by 2045. Between 2024 and 2045, the implied average annual growth rate is
23%. The forecast assumes each MDEV averages 12,700 kWh per year and MDEVs
will constitute 0.02% of all commercial light-duty vehicle sales by 2030 and 24% by
2045. The MDEV penetration rate is forecasted to rise from near 0% of commercial
vehicles in 2024 to just over 13% by 2045 for a total load of 23 aMW. The current data
on commercial MDEV in Avista's service area is limited, so the modeling assumptions
described above will have to be carefully reviewed in future forecasts.
Figure 2.12 shows the net impact of EV load additions against PV load reductions for
this forecast. There are three significant barriers to the rapid , near-term accumulation
of all types of EVs. The first is consumer preferences related to model options and
battery range. Although these barriers are slowly shrinking, the gap with traditional
internal combustion vehicles is still notable. This is important in Avista's service area
given the significant number of rural and suburban households and businesses.
Second, there is consumer uncertainty about the evolution of the public charging
infrastructure to support rapid adoption in the near term. Although improving, the
public charging infrastructure remains significantly underdeveloped compared to
traditional vehicles. Third is the willingness of consumers to rapidly abandon relatively
new traditional vehicles for EVs with similar characteristics that may require a higher
upfront cost. Third , there is evidence that production constraints (e.g., labor and rare
earths) may hold back supply even as demand grows via preferences or policies
outlawing internal combustion engines. Because of these barriers , as with previous
forecasts, this forecast assumes rapid adoption in Avista's service area will not start
until the early 2030s.
5. Rooftop Solar Installations Increase
Residential rooftop solar penetration, measured as the share of residential solar
customers to total residential customers, continues to grow at present levels in the
forecast. The starting average PV system size is set at 7 kW (DC) with a 14% capacity
factor, or about 8,500 kWh per year per customer. These values reflect current
Company data on customer installation size and system efficiency. The forecast
assumes the starting system size will increase 1 % annually to about 10,900 kWh per
year per customer in 2045, with the capacity factor remaining constant at 14%.
Company data on its residential customers show the system size is increasing over
time. In the 2005-2008 period, when solar installs were just beginning, the median
installed system size was about 1.8 kW. Consistent with recent history, the residential
PV penetration rate forecast follows a non-linear relationship between the penetration
rate in year t and the number of residential customers in year t. Under this assumption,
residential solar penetration will increase from 0.6% in 2024 to about 4.0% in 2045.
This accumulation can be approximated by an exponential growth function. The base-
Avista Corp 2023 Electric IRP 2-14
Chapter 2: Economic & Load Forecast
line model assumes residential solar penetration will grow approximately 9.0%
annually through 2045, producing 20 aMW in load reduction by 2045.
Commercial rooftop solar penetration, measured as the share of commercial solar
customers to total commercial customers, continues to grow at present levels in the
forecast. The starting average PV system size is set at 13 kW (DC) with a 14%
capacity factor, or about 28,200 kWh per year per customer. These values reflect
current Company data on customer installation size and system efficiency and
assumes the starting system size will increase 1 % annually to about 38,500 kWh per
year per customer in 2045, with the capacity factor remaining constant at 14%. Like
residential solar, this forecast assumes the commercial PV penetration rate will follow
a non-linear relationship between the penetration rate in year t and the number of
commercial customers in year t. Under this assumption , commercial solar penetration
will increase from 0.3% in 2024 to about 0.6% in 2045. This accumulation can be
approximated by an exponential growth function . The base-line model assumes
commercial solar penetration will grow at approximately 4.0% annually through 2045,
producing a 1 aMW in load reduction by 2045. Figure 2.12 shows the net impact of
EV and PV loads. As with EVs, there are several important barriers around the
accumulation of residential PV systems in Avista's service area. First, urban and rural
forests surround many of the owner-occupied structures. Tree shade can significantly
reduce solar generation. In the Spokane metro area, the largest metro area we serve,
many of the areas with fewer trees are lower-income areas and/or are mainly
composed of renter-occupied structures. Second, the heavy winter cloud cover also
reduces solar generation. Avista recognizes future improvements in solar panels can
reduce these barriers. For example, solar panels can be formed directly into roof top
shingles or home siding . However, like many utilities in the West, Avista has
discovered that smoke from wildfires can also significantly reduce the efficiency of
solar generation.
6. Natural Gas Customers Decline
Washington State's restrictions on using natural gas as a heating fuel and lowering
natural gas connection incentives is reflected by assuming no additional commercial
gas customers after 2023. This assumption means natural gas penetration will
experience a steady decline over the forecast horizon, reflecting a shift towards
electric usage. This is accounted for by taking the difference between a no-restriction
forecast for commercial gas customers (generated for Avista's 2023 Natural Gas IRP)
and the number of commercial gas customers held constant at the current forecast
level. An econometric estimate of UPC sensitivity to changes in the gas penetration
rate is used to generate a forecast of future load impacts. Washington State's
restrictions on using residential natural gas as a primary heating fuel and lowering
connection incentives is reflected by assuming 80% of potential new natural gas
customers will have heat pump heating systems with natural gas as the back-up
source for temperatures below 40 degrees, the remaining new customers will be 100%
electric. All new customers assume the use of an electric heat pump water heater.
Avista Corp 2023 Electric IRP 2-15
Chapter 2: Economic & Load Forecast
Figure 2.12: Electric Vehicle and Rooftop Solar Load Changes
160
140 -+-Electric Vehicle Load Addition
--solar Load Reduction 120 -Net Load Change
100
,.,,
:i:: 80 ni 3': ni Cl Q) 60 :Ii:
Q)
Cl ni ... 40 Q)
~
20
■ ■ ■ ■ ■ ■ --■ • ■ ■ •
0
-20
Long-Term Forecast Residential Retail Sales
Focusing on residential kWh sales, Figure 2.13 is the residential UPC growth plotted
against the EIA's annual growth forecast of U.S. residential use per household growth.
EIA's forecast is from the 2022 Annual Energy Outlook. EIA's forecast shows positive
UPC growth by the mid-2030s, while Avista's growth becomes positive in the early 2030s.
The higher EIA forecast reflects a population shift to warmer-climate states where air
conditioning is typically required most of the year. In contrast, Avista's forecast of positive
UPC growth starting in the early 2030s reflects the impact of regional EV growth.
Avista Corp 2023 Electric IRP 2-16
Chapter 2: Economic & Load Forecast
Figure 2.13: UPC Growth Forecast Comparison to EIA
1.5%
-e-EIA Refrence Case Use Per Household Growth
1.0%
0.5%
0.0%
-0.5%
-1 .0%
C') "<t ll) N N N 0 0 0 N N N
UPC Growth, Residential Expected Case
co N 0 N
r-­N 0 N
co N 0 N
Ol N 0 N
0 C') 0 N
~ C') 0 N
N C') 0 N
C')
C') 0 N
"<t C') 0 N
ll)
C') 0 N
co C') 0 N
r-­C') 0 N
co C') 0 N
Ol C') 0 N
0 c!;
N
~ "<t 0 N
N "<t 0 N
C')
c!;
N
ll)
"<t 0 N
Figure 2.14 shows EIA and residential load growth forecasts. Avista's forecast is higher
over the entire period, reflecting the assumptions for rapid EV adoption and a service
area population growth that will exceed the U.S. average. The higher population forecast
for Avista's service area is consistent with government and IHS forecasts for the far west
and Rocky Mountain regions where Avista's service territory is located.
2.5%
2.0%
1.5%
1.0%
0.5%
0.0%
-0.5%
-1.0%
-1.5%
-2.0%
Avista Corp
Figure 2.14: Load Growth Comparison to EIA
• • • • ■ • • • • • ■ ■ •
_,._EIA Purchased Residential Electricity Growth (Quad. BTU)
...,_Load Growth, Residential Expected Case
2023 Electric IRP 2-17
Chapter 2: Economic & Load Forecast
Future Temperature Forecast
As noted above, this forecast includes forecasted temperatures reflecting a warming
trend . Climate impacts reflect the temperature forecasts from the RCP 4.5 climate model.
The temperature forecast has a relatively small impact on annual load growth, but a
significant impact on the distribution of load within the calendar year. The impact on load
growth comes from the shift of load from winter to summer. However, the shift in load
shares remains notable. Figure 2.15 compares the monthly share of load in 2045 in the
Expected Case between the historical temperature method and RCP 4.5 forecast. In other
words, the only difference between the temperature methods is the time path of heating
and cooling degrees. That means, EV accumulation, solar accumulation , and natural gas
restrictions are the same between the two scenarios. Figure 2.16 shows the difference
between the static HOD and COD assumptions for the historical weather method, defined
by 20-year average of HOD and COD for the 2002-2021 period and the 20-year moving
average of HOD and COD predicted by the RCP 4.5 model.
Figure 2.15: Load Share Comparison Due to Temperature Forecasts
10.5% ,--------------------------------,
10.0%
~ 9.5% ..
.l: Cl)
7.5%
--2045, With No Climate Change
--2045, With RCP 4.5
7.0% c__ ____________________________ __,
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Avista Corp 2023 Electric IRP 2-18
Chapter 2: Economic & Load Forecast
7,200
7,000
6,800
6,600
6,400
6,200
6,000
5,800
5,600
Figure 2.16: Load Share Comparison Due to Temperature Assumptions
HDD
.... ..... ..... .... .... .... ..... .... .... ..... .....
--HOD, 20-yr Moving Average --HOD, Current 20-yr Average ---HOD, RCP 4.5 20-yr Moving Average
700
650
600
550
500
450
400
350
300
--COD, 20-yr MA
CDD
--COD, Current 20-yr Average ---COD, RCP 4.5 20-yr Moving Average
Monthly Peak Load Forecast Methodology
The Peak Load Regression Model
The peak load hour forecast is used to determine the number of resources necessary to
meet system peak demand. Avista must build generation capacity to meet winter and
summer peak periods. Future highest peak loads will most likely occur in the winter
months, although in some years a mild winter followed by a hot summer could find the
annual maximum peak load occurring in a summer hour. Equation 2.4 shows the current
peak load regression model.
Avista Corp 2023 Electric IRP 2-19
Chapter 2: Economic & Load Forecast
Equation 2.4: Peak Load Regression Model
Where: • hMw;;,ieak = metered peak hourly usage on day of week d, in month t, in
year y, and excludes two large industrial producers and special peak adders
for future EVs, solar, and gas restrictions. The data series starts in June
2004.
• HDDct,t,y and CDDct,t,y = heating and cooling degree days the day before the
peak.
• (HDDct,t,y)2 = squared value of HDDci,t,y.HDDct-i,t,y and CDDct-i,t,y = heating
and cooling degree days the day before the peak.
• CDD~J~H = maximum peak day temperature minus 65 degrees.14
• GDPt.y-i = extrapolated level of real GDP in month tin year y-1 .
• (DsuM * GDPt.y-i) is a slope shift variable for GDP in the summer months,
June, July, and August.
• (DwiN * GDPt.y-i) is a slope shift variable for GDP in the winter months,
December, January, and February.
• wwoDd,t,y = dummy vector indicating the peak's day of week.
• ws0D1,y = seasonal dummy vector indicating the month; and the other
dummy variable control for an extreme outliers in March 2005.
• Ed,t,y = uncorrelated N(O, o) error term.
Peak Growth Rates Based on a GDP Driver and Temperatures
The estimated regression Equation 2.4 is used to generate future peak loads by month
for the 2022-2045 period. This is done by (1) assuming a long-term average annual
growth rate in GDP of 1.8% to 2045 (this is consistent with the assumption in the expected
energy forecast) and an extreme temperature forecast derived using RCP 4.5 forecasts.
Because the RCP 4.5 forecasts are based on daily data, the RCP 4.5 forecasts are
smoothed to capture trends that can be obscured by daily volatility. The smoothed
temperatures are then used to calculate the monthly HOD and COD required for
regression equations. The temperatures in months January to May and October to
December are smoothed with historical actuals using a 76-year moving average (the
average starts with data back to the late 1940s). The months June to September are
smoothed with historical actuals using a 20-year moving average (the average starts with
data back to the early 2000s).
14 This term provides a better model fit than the square of COD.
Avista Corp 2023 Electric IRP 2-20
Chapter 2: Economic & Load Forecast
The use of a moving average blended with historical and forecasted extremes in colder,
HDD months reflects that although warming has occurred, the possibility of extreme cold
is still possible. In other words, although average winter temperatures have risen in the
Company's service area, and are expected to increase further under RCP 4.5, the
distribution of extreme cold temperatures is still left-skewed-meaning there is still a
greater likelihood of an unusually cold winter compared to an unusually warm winter.
Blending both historical and forecasted temperatures means that skewness remains in
place for planning purposes. Conversely, the use of a shorter moving average in warmer,
CDD months means the peak forecast will more rapidly reflect the shift towards warmer
summer temperatures predicted by RCP 4.5.
Using a 76-year moving average in cold months and 20-year moving average in warmer
months maintains a winter temperature distribution that maintains the possibility of winters
skewed towards extreme cold temperatures and a summer distribution that is increasingly
skewed towards warmer summer temperatures than historically observed. As seen in the
peak load forecast with RCP 4.5, and with the adders for future EVs, solar, and gas
restrictions, Avista will need to prepare for a near-term future as a dual summer and winter
peaking utility.
The finalization of the peak load forecast occurs when the forecasted peak loads of two
large industrial customers, EVs, solar, and gas restrictions are added to the forecasts
generated by Equation 2.4. Table 2.3 shows estimated peak load growth rates with and
without these adders. Figure 2.17 shows the forecasted time path of peak load out to
2045, and Figure 2.18 shows the high/low bounds based on a 1-in-20 event (95%
confidence interval) using the standard deviation of the simulated historic peak loads. The
potential impact of time-of-use pricing or other demand response options is not yet
reflected in the current peak load forecast as it may or may not be used as a method to
manage this load.
Table 2.3: Forecasted Winter and Summer Peak Growth, 2021-2045
Peak Load Annual Growth Winter Summer
Including Economic Growth, Large Industrial Customers, and 1.16 1.24 adders for EVs, Solar, and WA Gas Restrictions
Including Economic Growth, but Excluding Large Industrial 0.13 0.67 Customers, and adders for EVs, Solar, and WA Gas Restrictions
Figure 2.17 shows how the summer peak forecast grows faster than the winter peak, but
the rapid accumulation of EVs results in similar winter and summer peaks over the
forecast horizon. Figure 2.18 shows that the winter high/low bounds are larger than
summer and reflects a historically greater range of temperature anomalies in the winter
months.
Avista Corp 2023 Electric IRP 2-21
)>
~-Megawatts Megawatts
oi .....l. .....l. .....l. -1t. ....,l,. N N N N -1r,. .....l. -1,, .....l. -Jo. N N N
0
() 0 .N ".i,. "m co ·o .N ~ 0) ·o .N ~ 0) co O .N ~
0 0 0 0 0 0 0 0 O O O O O O O O 0 -0 0 0 0 0 0 0 0 0 O O O O O O O O 0
1997 1997
1999 I I f ; 1 999
2001 cn ::§: ::§: ~ 2001
C: -· -· 2003 3 3. 3. "' 2003 3 ~ ~ ~
2005 ~ ::X: 7J ex> 2005 -· (D ICODl "ti 2007 (0° :::r " (P 2007 :::r Q)
2009 " 2009 :!!
I I t r ~ I I C: 2011 I I g 2011 -,
(f) ::§: (f) ~ (P
2013 c: -· c: "Tl 2013 "' ~ 3 3. 3 O ~
N 2015 3 ~ 3 -, 2015 ....... (.,J <D'<D (P 7 r -, C'> "ti
!!! 2017 r ~ ~ t::ll 2017 --~.....,-. m ~ ~ Ql (fl Q)
::;-2019 " -2019 " n· :§. r ~ ~21 ~ 2~1 g
~ ~ ~ 2023 1 .!.. 2023 "Tl
'' ::I 0 2025 I I ~ 2025 ~
'' 0 C') 2027 \ \ \ ::c 2027 t::ll g
' ' <.0' !!!. Ql 2029 , 1 \ :::r 2029 "S?. ,, -ro
2031 \\ , b 2031 ;;,
2033 \ \ \ ! 2033 t t ~
\ ' 0 g, ::§: g 2035 , \ \ c: 2035 3 3. o ,, ::, 3 <D 3
2031 , \ , ~ 2031 ~ ~ n· \, "' 7JIB s,o 2039 , , , 2039 IB ,... r
\ \ " 0
2041 \\ \ 2041 g_
'\ ~ 2043 \ , \ 2043 o
N ,, \ CD
N 2045 '\ , 2045 '---------------------=-=----£
N ~
Chapter 2: Economic & Load Forecast
Table 2.4: Energy and Peak Forecasts
Year Energy Winter Peak Summer Peak
(aMW) (MW) (MW)
2023 1,113 1,718 1,661
2024 1,121 1,728 1,670
2025 1,126 1,736 1,684
2026 1,132 1,743 1,697
2027 1,140 1,754 1,710
2028 1,147 1,762 1,717
2029 1,154 1,778 1,727
2030 1,161 1,790 1,745
2031 1,169 1,809 1,768
2032 1,179 1,828 1,789
2033 1,187 1,843 1,815
2034 1,1 97 1,866 1,836
2035 1,207 1,886 1,855
2036 1,218 1,907 1,879
2037 1,228 1,932 1,906
2038 1,239 1,957 1,931
2039 1,251 1,984 1,960
2040 1,265 2,014 1,986
2041 1,277 2,050 2,017
2042 1,292 2,086 2,054
2043 1,307 2,126 2,095
2044 1,325 2,168 2,135
2045 1,342 2,212 2,177
Scenario Analysis
Native Load Scenarios with Low/High Economic Growth
The load forecast for this IRP also considers futures with higher and lower loads due to
higher or lower economic growth. The high and low load scenarios use the GDP growth
and population growth assumptions shown in Table 2.5. The GDP growth assumptions
are used to forecast long-run industrial production growth. Then growth is used to forecast
the long-run growth rate in industrial customer UPC. The population growth assumptions
are used to forecast residential customer growth. This assumption is then used to forecast
long-run commercial customer growth. The forecasts are based on underlying
regressions using annual data to estimate the long-run sensitivity of (1) U.S. industrial
production growth to GDP growth; (2) industrial customer UPC growth to U.S industrial
production growth; (3) changes in residential customers to changes in population; (4)
changes in commercial customers to changes in residential customers.
Underlying the high/low range of GDP forecasts is the following long-run and well­
established relationship: U.S. GDP growth is equal to U.S. population growth plus U.S.
labor productivity growth. The U.S. Census forecast for average annual U.S. population
growth over the IRP's forecast horizon is 0.5%. Given long-run demographic realities in
the U.S., this will not likely vary significantly so it is held constant as a source of GDP
variability. This leaves labor productivity as the primary driver of long-run GDP growth.
Avista Corp 2023 Electric IRP 2-23
Chapter 2: Economic & Load Forecast
Given a 0.5% annual population growth, the Expected Case of 1.8% GDP growth implies
labor productivity growth of 1.3%; this is in line with the annual productivity growth
observed since the end of the Great Recession . The high case of 2.4% GDP growth
implies annual productivity growth of 1.9%; this level is near pre-Great Recession growth.
The low case of 1.2% GDP growth implies only 0.7% annual productivity growth. This
level is low by all historical standards, but not improbable given the productivity slowdown
being observed in most developed economies.
The high and low GDP growth cases are simultaneously paired with high and low regional
population growth. As noted in Figure 2.1, periods of higher (lower) economic growth
tends to be associated with higher (lower) service area population growth, especially
through in-migration. To help identify reasonable high/low population growth ranges,
Equation 2.5 is applied.
Equation 2.5: Population Growth Long-Run Forecast Relationship
POPG = (0.005 + a10.005us + a2 EMPGsPK) · W + (0.005 + b1 0.005us + b2EMPGKoor)
· (1-W)
Where:
• POPG = predicted population growth rate for the combined Spokane-Kootenai
metro area.
• a = the estimated regression coefficients from the Spokane metro population
growth forecast equation used for the medium-term forecast. These reflect the
sensitivities of a change in U.S. employment growth (a1<0) and Spokane metro
employment growth (a2>0) on Spokane metro population growth. Note that 0.005
is the Bureau of Labor Statistics' (BLS) forecast for long-run annual U.S.
employment growth and EMPGsPK is the assumed high/low growth rate for
Spokane metro.
• b = the estimated regression coefficients from the Kootenai metro population
growth forecast equation medium-term forecast. These reflect the sensitivities of a
change in U.S. employment growth (b1<0) and Kootenai metro employment growth
(b2>0) Kootenai metro population growth. As before, 0.005 is the BLS's forecast
for long-run U.S. employment growth and EMPGKoor is the assumed high/low
growth rate for the Kootenai metro area.
• 0.005 = the intercept term replacing the original intercept from the medium-term
regression equations. It reflects the long-term U.S. Census forecast for annual U.S.
population growth (0.5%) over the IRP's forecast period. The assumption here is
as annual service area employment growth gets closer to U.S. employment
growth, the incentive for people to migrate to the combined metro region for
economic reasons declines to the neighborhood of national population growth.
• W = the share of population in the Spokane metro as a share of the total population
the combined Spokane-Kootenai metro area. This provides a weight to produce a
combined area population growth rate.
Avista Corp 2023 Electric IRP 2-24
Chapter 2: Economic & Load Forecast
Using the historical regression relationship between U.S. GDP growth and service area
employment growth (see Figure 2.19), Equation 2.5 can be used to identify population
growth rates that are consistent with long-run GDP growth rates in the neighborhood of
2.4% and 1.2% holding long-run U.S. employment growth constant. The high and low
population ranges identified using this method are similar to calculating the approximate
75th and 25th percentiles of annual population growth changes since the early 1990s,
and then adding those percentile changes to the expected population growth case.
U) --C'O s": C'O C)
Cl)
~
Cl)
C)
C'O ...
Cl)
cri
Table 2.5: High/Low Economic Growth Scenarios (2027-2045)
2.4
Low Growth 1.2
Figure 2.19: Average Megawatts, High/Low Economic Growth Scenarios
1,450
1,400
1,350
1,300
1,250
1,200
1,150
1,100 -Expected Case
-High Growth Rate
1,050 -Low Growth Rate
1,000
Table 2.6 shows the average annual load growth rate over the 2021-2045 period.
Compared to the 2021 IRP, the last IRP assumed a low growth scenario with slightly
negative growth of the 2025-2041 timeframe, this IRP shows positive load growth in all
cases. This reflects the impact of a more aggressive EV forecast and commercial gas
restrictions in Washington.
Avista Corp 2023 Electric IRP 2-25
Chapter 2: Economic & Load Forecast
Table 2.6: Load Growth for High/Low Economic Growth Scenarios (2023-2045)
Low Growth
In the sections that follow, four alternative scenarios are considered. Each of these
scenarios are compared against the Expected Case for both energy and peak. These
scenarios are (1) Full building electrification in Washington; (2) Building electrification in
Washington with natural gas as a backup; (3) high electric vehicle (EV) adoption
throughout A vista's Washington and Idaho jurisdictions; and (4) a transformative scenario
that reflects scenarios (1) and (3) combined with much higher solar adoption in
Washington.
Washington Building Electrification (Full Electrification)
In this scenario, Expected Case is altered by assuming that all existing and new natural
gas customers will gradually move to electric only service -there are no additional gas
connects for new customers and existing customers gradually switch to electric only
service. Solar and EV accumulation are assumed to be the same as the Expected Case.
The results are shown in Figures 2.20-2.22. The first graph in the figure shows energy
compared to the Expected Case, the second shows winter peak compared to the
Expected Case; and the third shows the summer peak compared to the Expected Case.
1,600
1,500
J!! 1,400 -Ill
== 1,300 Ill Cl CII ::!!:
CII 1,200 Cl Ill ... CII ~ 1,100
1,000
900
Avista Corp
Figure 2.20: Full Building Electrification -Energy Impact
--Expected Case Native Load
-Full Building Electrification Scenario Native Load
~ ~ ~ ~ ~ ~ g ~ ~ ~ ~ ~ ~ M ~ ~ ~ ~ ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
2023 Electric IRP 2-26
Chapter 2: Economic & Load Forecast
Figure 2.21: Full Building Electrification -Winter Peak Impact
3,500
--Expected Case Native Load
3,000 ._Full Building Electrification Scenario Native Load
2,500
.'!! ~ ~ ta 2,000 Cl GI ::E
1,500
1,000 ..,. "' co ,.__ <O O> 0 ;;; N "' ..,. "' co ,.__ <O O> 0 :;: N "' ..,. "' N N N N N N "' "' "' "' "' "' "' "' "' ..,. ..,. ..,. ..,. ..,.
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Figure 2.22: Full Building Electrification -Summer Peak Impact
2,500
--Expected Case Native Load
2,300 ._Full Building Electrification Scenario Native Load
2,100
.'!! ~ ~ 1,900 ta Cl GI ::E
1,700
1,500
1,300 ..,. "' co ,.__ <O O> 0 ;;; N "' ..,. "' co ,.__ <O O> 0 :;: N "' ..,. "' N N N N N N C') C') C') C') C') C') C') C') C') ..,. ..,. ..,. ..,. ..,.
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Washington Building Electrification (Electrification w/ Natural Gas Backup)
In this scenario, the Expected Case is altered by assuming that all existing and new
natural gas customers will gradually move to electric service with natural gas as a backup
during temperatures below 40 degrees. New customers will add gas only as a backup
and existing gas customers gradually switch to electric with gas only as a backup. Solar
and EV accumulation are assumed to be the same as the Expected Case. The results
are shown in Figure 2.23-2.25. The first graph in the figure shows energy compared to
the Expected Case, the second shows winter peak compared to the Expected Case; and
the third shows the summer peak compared to the Expected Case.
Avista Corp 2023 Electric IRP 2-27
(/) .... -;
1,600
1,500
1,400
~ 1,300
Cl CIJ :E
~ 1,200
~ CIJ ~ 1,100
1,000
900
2,750
2,500
2,250
.l!l 2,000
-; := ~ 1,750 Cl CIJ :E
1,500
1,250
1,000
Avista Corp
.,.
N 0 N
.,.
N 0 N
Chapter 2: Economic & Load Forecast
Figure 2.23: Hybrid Electrification -Energy Impact
-Expected Case Native Load
-Electric with Gas Backup Scenario Native Load
1/)
N 0 N
(!) ,._
N N 0 0 N N
<Xl N 0 N
0)
N 0 N
0 C') 0 N
C') 0 N
N C')
0 N
C')
C') 0 N
.,.
C')
0 N
1/)
C') 0 N
(!)
C') 0 N
,._
C') 0 N
<Xl C') 0 N
0)
C') 0 N
0 .,.
0 N
Figure 2.24: Hybrid Electrification -Winter Peak Impact
-Expected Case Native Load
-Electric with Gas Backup Scenario Native Load
1/) (!) ,._ <Xl 0) 0 n N C') .,. 1/) (!) ,._ <Xl 0) 0 N N N N N C') C') C') C') C') C') C') C') C') .,.
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N
2023 Electric IRP
.,.
0 N
;;;
0 N
N .,.
0 N
N .,.
0 N
C') .,.
0 N
C') .,.
0 N
.,. .,.
0 N
1/) .,.
0 N
1/) .,.
0 N
2-28
Chapter 2: Economic & Load Forecast
Figure 2.25: Hybrid Electrification -Summer Peak Impact
2,500
2,300 -Expected Case Native Load
-Electric with Gas Backup Scenario Native Load
2,100
II) = ra 3: 1,900 ra Cl CIJ :l!:
1,700
1,500
1,300
'q-.,, (0 r--<X) Ol 0 ;;; N (") 'q-.,, (0 r--<X) Ol 0 :;;: N (") 'q-.,,
N N N N N N (") (") (") (") (") (") (") (") (") 'q-'q-'q-'q-'q-
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
High Electric Vehicle Adoption
In this scenario, the Expected Case is altered by only changing the assumption of the
accumulation of light and medium duty EVs. Table 2.7 shows the change in assumption
between the Expected Case and the scenario. The 2050 date is used because this is the
year frequently quoted as the goal-year for state-level policy statements regarding EV
targets as a percent of sales. For example, along with several other states, Washington
has a target of 2050 for LDVs to be 100% of new car sales.
Table 2.7: EV Percent of Sales Comparison between Expected and Scenario
LDV Expected LDV Scenario, MDV Expected MDV Scenario,
Case, Percent of Percent of Case, Percent of Percent of
Jurisdiction Vehicle Sales by Vehicle Sales Vehicle Sales by Vehicle Sales
2050 by 2050 2050 by 2050
Idaho 41% 75% 50% 75%
The results are shown in Figure 2.26-2.28. The first graph in the figure shows energy
compared to the Expected Case, the second shows winter peak compared to the
Expected Case; and the third shows the summer peak compared to the Expected Case.
Avista Corp 2023 Electric IRP 2-29
1,600
1,500
1,400
2 7v ,: 1,300 "' Cl QJ ::!: 1,200 QJ Cl "' ... QJ 1,100 ~
1,000
900 ... N 0 N
2,750
2,500
2,250
Cl) 2,000 :::: "' ,:
"' 1,750 Cl QJ ::!:
1,500
1,250
1,000
Avista Corp
Chapter 2: Economic & Load Forecast
Figure 2.26: High EV Adoption -Energy Impact
-Expected Case Native Load
..... High EV Adoption Scenario Native Load
"' "' ,,_ C0 a, 0 ;;; N "' ... "' "' ,,_ C0 a, 0 N N N N N "' "' "' "' "' "' "' "' "' ... 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N
Figure 2.27: High EV Adoption -Winter Peak Impact
-Expected Case Native Load
..... High EV Adoption Scenario Native Load
~ ~ ~ ~ ~ ~ g M 0 0 0 0 0 0 0 0 N N N N N N N N
N M "' "' 0 0 N N
... (") 0 N
"' (") 0 N
2023 Electric IRP
"' (") 0 N
,,_
"' 0 N
C0 a, "' "' 0 0 N N
0 2;
N
:;
0 N
... 0 N
N ... 0 N
N 2; N
"' ... 0 N
(")
2;
N
... ... 0 N
... 2; N
"' ... 0 N
"' ... 0 N
2-30
Chapter 2: Economic & Load Forecast
Figure 2.28: High EV Adoption -Summer Peak Impact
2,700
2,500
2,300
.!!.! 2,100 'la
== I'll
Cl Cl.I 1,900 :!:::
1,700
1,500
1,300
-Expected Case Native Load
-High EV Adoption Scenario Native Load
U') <O N N 0 0 N N
.... N 0 N
CX) a,
N N 0 0 N N
0 (") 0 N
(") 0 N
N (") 0 N
Washington Energy Transformation
(")
(") 0 N
'St (")
0 N
U')
(") 0 N
<D (")
0 N
.... (")
0 N
CX)
(")
0 N
a,
(")
0 N
0 'St 0 N
'St 0 N
N 'St 0 N
(")
'St 0 N
U')
'St 0 N
In this scenario, the Expected Case is altered by using the scenarios for full electrification
of buildings and high EV sales in conjunction with a more aggressive assumption of
residential and solar penetration in Washington. The higher solar penetration is shown in
Table 2.8.
Table 2.8: WA Solar Percent of Customer Comparison between Expected and Scenario
WA Residential WA Residential WA Commercial WA Commercial
Expected Case, Scenario, Expected Case, Scenario,
Jurisdiction Percent of Percent of Percent of Percent of
Customers by Customers by Customers by Customers by
2045 2045 2045 2045
Washin ton 6% 20% 0.8% 5%
The results are shown in Figure 2.29-2.31. The first graph in the figure shows energy
compared to the Expected Case, the second shows winter peak compared to the
Expected Case; and the third shows the summer peak compared to the Expected Case.
Avista Corp 2023 Electric IRP 2-31
Chapter 2: Economic & Load Forecast
Figure 2.29: Full Electrification and High EV and Solar Adoption -Energy Impact
1,900 ~----------------------------------~
1,700
2
"; 1,500
rel Cl QJ
:ii:
8i 1,300 ~ QJ ~
1,100
-Expected Case Native Load
-Full Electrification and High Adoption EV and Solar Scenario Native Load
900 --'-------------------------------------~
'VU')<Or---.CO N N N N N 0 0 0 0 0 N N N N N
~ g ~
0 0 0 N N N
N M -c:t Lt') C"') C"') C"') C"') a o o o N N N N
co r---co 0) C"') C"') C"') C"')
0 0 0 0 N N N N
0 ........ 0 0 N N
N .... 0 N
"' .... "' .... .... .... 0 0 0 N N N
Figure 2.30: Full Electrification and High EV and Solar Adoption -Winter Peak Impact
3,900
-Expected Case Native Load
-Full Electrification and High Adoption EV and Solar Scenario Native Load
3,400
2,900
2 (Q 2,400 3: rel Cl QJ :ii: 1,900
1,400
900 .... "' <O ,-.. "' Ol 0 ;;:; N "' .... "' <O ,-.. "' Ol 0 ; N "' .... "' N N N N N N "' "' "' "' "' "' "' "' "' .... .... .... .... .... 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Avista Corp 2023 Electric IRP 2-32
Chapter 2: Economic & Load Forecast
Figure 2.31: Full Electrification and High EV and Solar Adoption -Summer Peak Impact
2,700
2,500
2,300
(/) ~ 2,100
3: rtl Cl C1> 1,900 :E
1,700
1,500
1,300
Avista Corp
+ Expected Case Native Load
--Full Electrification and High Adoption EV and Solar Scenario Native Load
'C:t I.() (0 ,._ co N N N N N 0 0 0 0 0 N N N N N
0) 0 N ('") 0 0 N N
('")
0 N
N ('")
0 N
('") ('")
0 N
.... ('")
0 N
U') ('")
0 N
2023 Electric IRP
CD ,..._
('") ('")
0 0 N N
a, ('")
0 N
0) ('")
0 N
0 .... 0 N
.... 0 N
N .... 0 N
('") .... .... .... 0 0 N N
U') .... 0 N
2-33
Chapter 2: Economic & Load Forecast
This Page is Intentionally Left Blank
Avista Corp 2023 Electric IRP 2-34
Chapter 3: Existing Supply Resources
3. 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.
Section Highlights
• Hydro represents approximately half of Avista's winter generating capability.
• Natural gas-fired plants represent the largest portion of Avista's thermal
generation portfolio.
• Avista agreed to transfer ownership of Colstrip 3 & 4 to Northwestern Energy
on January 1, 2026.
• Recently signed hydro agreements with Chelan PUD and Columbia Basin
Hydro are included within the plan.
• Avista plans to upgrade Kettle Falls Generating Station and Post Falls
Hydroelectric Development.
• The Lancaster PPA is extended through 2041 as a result of the recent RFP
process.
Figure 3.1 shows Avista 's winter and summer resource capacity mix and Figure 3.2
shows the energy mix, considering the production capability rather than maximum
generating capacity. Winter capability is the share of total capability of each resource type
the utility can rely upon to meet winter peak load. The annual energy chart represents the
energy as a percent of total supply; this calculation includes fuel limitations (for water,
wind, and wood), maintenance and forced outages. Avista's largest energy supply in the
peak winter months is from hydro at 50%, followed by natural gas-fired resources at 37%.
On an annual basis, natural gas-fired generation can produce more energy (45%) than
hydro (31%) because it is not constrained by fuel limitations (i.e., river conditions). The
resource mix changes each year depending on streamflow conditions and market prices.
Figure 3.1: 2024 Avista Seasonal Capability
Winter Peak Capability
Net
Contracted_
Hydro
9%
Avista Corp
Natural Gas
37%
Summer Peak Capability
Biomass,
Wind, Solar,
& Refuse
5%
Net
Contracted~
Hydro
11%
2023 Electric IRP
Natural Gas
33%
Biomass,
Wind, Solar,
& Refuse
6%
3-1
Chapter 3: Existing Supply Resources
Figure 3.2: 2024 Annual Energy Capability
Natural Gas
45%
Coal
11%
Avista reports its fuel mix annually in the Washington State Fuel Mix Disclosure 1. The
Washington State Department of Commerce calculates the resource mix used to serve
load, rather than generation potential, it also adds estimates for regional2 unassigned
market purchases and Avista-owned generation minus net renewable energy credit
(REC) sales. Figure 3.3 shows the draft Avista's 2021 Fuel Mix Disclosure. The Idaho
fuel mix is nearly identical to Washington's except for its allocation of Public Utility
Regulatory Policies Act (PURPA) generation. Each state receives RECs based on their
current authorized share of the system (approximately 65% Washington and 35% Idaho).
Avista may retain RECs, sell them to other parties or transfer them between states. Avista
transfers RECs from Idaho to comply with Washington's Energy Independence Act (EIA).
Idaho customers are compensated for the value of RE Cs at market value whenever these
transfers occur.
Figure 3.3: 2021 Avista's Washington State Fuel Mix Disclosure
Other
Natural Gas
40%
Biogenic
1%
L .,m
0%
Waste
Wind 1%
3%
Biomass
6%
1 11 A-Utility-Fuel-Mix-Market-Summary-23.5.2-1 .pdf from Dep. of Commerce.
2 For 2020, the region is approximately 55% hydroelectric, 13% natural gas, 11 % unspecified, 10% coal,
4% nuclear, 5% wind and 1 % other. When Avista sells RE Cs from its resources they are assigned an
emissions level in the report equal to regional average emissions.
Avista Corp 2023 Electric IRP 3-2
Chapter 3: Existing Supply Resources
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. Congress. This section
describes the Spokane River hydroelectric developments and provides the maximum on­
peak and nameplate capacity ratings for each plant. The maximum on-peak capacity of
a generating unit is the total amount of electricity it can safely generate with its existing
configuration and the current mechanical state of the facility. Unlike other generation
assets, hydro capacity is often above nameplate because of plant upgrades and favorable
head or streamflow conditions. The nameplate, or installed capacity, is the original
capacity of a plant as rated by the manufacturer. All six hydroelectric developments on
the Spokane River connect directly to the Avista transmission system .
Post Falls
Post Falls is the hydroelectric facility furthest upstream on the Spokane River. It is located
several miles east of the Washington/Idaho border. The facility began operating in 1906
and during summer months maintains the elevation of Lake Coeur d'Alene. Post Falls
has a 14. 75 MW nameplate rating but can produce up to 18.0 MW with its six generating
units. Avista is currently evaluating upgrades to this facility as the generators and turbines
are near end of life3 this plan assumes turbine and generator replacement by 2029.
Upper Falls
The Upper Falls development sits within the boundaries of Riverfront Park in downtown
Spokane. It began generating in 1922. The project is comprised of a single 10.0 MW unit.
Monroe Street
Monroe Street was Avista's first generation development. It began serving customers in
1890 in downtown Spokane at Huntington Park. Following a complete rehabilitation in
1992, the single generating unit has a 15.0 MW maximum capacity rating.
Nine Mile
A private developer built the Nine Mile development in 1908 near Nine Mile Falls,
Washington. Avista purchased the project in 1925 from the Spokane & Inland Empire
Railroad Company. Nine Mile has undergone substantial upgrades with the installation of
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.
3 Currently the one and a half units are not able to produce power.
Avista Corp 2023 Electric IRP 3-3
Chapter 3: Existing Supply Resources
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. 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 requi rements.
Clark Fork River Hydroelectric Development
The Clark Fork River Development includes hydroelectric projects located near Clark
Fork, Idaho, and Noxon , Montana, 70 miles south of the Canadian border on the Clark
Fork River. The plants operate under a FERC license through 2046 and connect directly
to the Avista transmission system.
Noxon Rapids
The Noxon Rapids development includes four generators installed between 1959 and
1960, and a fifth unit that entered service in 1977. Avista completed major turbine
upgrades on units 1 through 4 between 2009 and 2012. The total capability of the plant
is 610 MW under favorable operating conditions, although Avista uses 555 MW for
planning purposes.
Cabinet Gorge
Cabinet Gorge started generating power in 1952 with two units, and two additional
generators were added the following year. Upgrades to units 1 through 4 occurred in
1994, 2004, 2001, and 2007, respectively. The current maximum on-peak plant capacity
is 270.5 MW, modestly above its 265.2 MW nameplate rating.
Total Hydroelectric Generation
In total, Avista's hydroelectric plants have nearly 1,080 MW of capacity. Table 3.1
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 3.1: Avista-Owned Hydroelectric Resources
Project Name River location Nameplate Maximum Expected
System Capacity Capability Energy
(MW) (MW) (aMW)
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
Total 972.4 1,079.9 442.3
Avista Corp 2023 Electric IRP 3-4
Chapter 3: Existing Supply Resources
Thermal Resources
Avista owns seven thermal generation assets located across the Northwest. These assets
provide dependable energy and capacity serving base and peak-load obligations. Table
3.2 summarizes these resources by fuel type, online year, remaining design life, book
value at the end of 2022 and the last year of expected service for IRP modeling purposes.
Table 3.3 includes capacity information for each of the facilities along with the five-year
historical forced outage rates used for modeling purposes.
Table 3.2: Avista-Owned Thermal Resources
Project Name Location Fuel Start Last Year Book Value Book Life
Type Date of Service4 (mill.$) (years)
Colstrip 3 & 4 Colstrip, MT Coal 19845 2025 50.2 See Note6
Rathdrum Rathdrum, ID Gas 1995 2044 27.5 10
Northeast Spokane, WA Gas 1978 2035 0.0 07
Boulder Park Spokane, WA Gas 2002 2040 14.0 17
Coyote Springs 2 Boardman , OR Gas 2003 n/a 116.6 17
Kettle Falls Kettle Falls, WA Wood 1983 n/a 61.6 18
Kettle Falls CT Kettle Falls, WA Gas 2002 2040 2.6 8
Table 3.3: Avista-Owned Thermal Resource Capability
Project Name Winter Summer Nameplate Forced
Maximum Maximum Capacity (MW) Outage Rate
Capacity (MW) Capacity (MW) (%)
Colstrip 3 111 111 123.5 7.4
Colstrip 4 111 111 123.5 7.4
Rathdrum (2 units) 176 130 166.2 1.9
Northeast (2 units) 66 42 61.8 1.9
Boulder Park (6 units) 24.6 24.6 24.6 11.4
Coyote Springs 2 317.5 286 306.5 5.0
Kettle Falls 47 47 50.7 3.7
Kettle Falls CT 11 8 7.2 6.2
Total 864.1 759.6 864.0
Colstrip Units 3 and 4
The Colstrip plant, located in eastern Montana, consists of two coal-fired steam plants
(Units 3 and 4) 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.
4 The last year of service is estimated retirement or end of service for utility customers. This IRP assumes
Coyote Springs 2 to be ineligible for Washington in 2045, but eligible to serve Idaho customers.
5 Colstrip Unit 3 began operating in 1984 and Colstrip Unit 4 began in 1986.
6 Avista is modeling Colstrip Units 3 and 4 with a depreciable life ending in 2025 in Washington and 2027
in Idaho, as approved by the Washington and Idaho Commissions. This may be adjusted for the next IRP
with Colstrip leaving Avista's portfolio at the end of 2025.
7 There is no remaining book life but there are seven years of remaining tax depreciation impacts to
customers.
Avista Corp 2023 Electric IRP 3-5
Chapter 3: Existing Supply Resources
Energy moves across both segments of the transmission line under a long-term wheeling
arrangement. Talen Montana, LLC operates the facilities on behalf of the six owners (see
Table 3.4). Avista currently owns 15% of Units 3 and 4. Unit 3 began operating in 1984
and Unit 4 in 1986. Avista's share of Colstrip has a maximum net capacity of 222 MW,
and a nameplate rating of 247 MW. Beginning on December 31 , 2025, ownership of
Colstrip will be transferred to Northwestern Energy and therefore will no longer serve
Avista customers. NorthWestern will assume all of Avista's Colstrip ownership along with
its related interest in the plant, plant equipment, rights, and obligations. Under the
Agreement, Avista retains its existing remediation obligations and enters into a vote
sharing agreement with NorthWestern to retain voting rights in regard to any decisions
made with respect to remediation activities. In addition, while NorthWestern will have the
right to exercise Avista's vote with respect to capital expenditures between now and 2025,
the Agreement is structured such that A vista's contribution to those expenditures is limited
to its pro rata share between the date of the expenditure and 2025, and to the least-cost
alternative available, thereby ensuring that the costs directly benefit Avista customers and
don't, in and of themselves , extend the life of the plant. The Agreement also preserves
Avista's rights in the Colstrip transmission system.
Table 3.4: Current Colstrip Ownership Shares
Year On-Line
Owners
Avista 15% 15%
No 0% 30%
PacifiCor 10% 10%
Portland General Electric 20% 20%
30% 0%
25% 25%
Coal Supply
Colstrip is supplied from an adjacent coal mine under coal supply and transportation
agreements. A vista's coal supply agreement runs through 2025. The specific terms of the
agreement are confidential.
Water and Waste Management
Colstrip uses water from the Yellowstone River for steam production , air pollution
scrubbers and cooling purposes. The water travels through a 29-mile pipeline to Castle
Rock Lake, a surge pond and water supply source for the plant and the Town of Colstrip.
From Castle Rock Lake, water moves to holding tanks as needed throughout the plant
site. The water recycles until it is ultimately lost through evaporation, also known as zero­
discharge. An example of this reuse is how the plant removes excess water from the
scrubber system fly ash, creating a paste product similar to cement. The paste flows to a
holding pond while clear water is reused. Similarly, the bottom ash flows to a holding
pond, where it is dewatered and the water is reused.
Avista Corp 2023 Electric IRP 3-6
Chapter 3: Existing Supply Resources
The plant uses three major areas for water and waste management. The first are at-plant
facilities, where all four units, including the now-retired Units 1 and 2, share use of the
ponds. The second major area, supporting Units 3 and 4 operations, is the Effluent
Holding Pond (EHP). This area is 2.5 miles to the southeast of the plant site. Avista is
responsible for its proportional share of the EHP Area. The third storage area is the Stage
One Effluent Pond (SOEP)/Stage Two Effluent Pond (STEP); these ponds dispose fly
ash from the scrubber slurry/paste from Units 1 and 2. These ponds are nearly two miles
to the northwest of the plant. Avista does not have ownership or responsibility in this area.
Avista is therefore responsible for its share of the plant site area and EHP facilities.
Colstrip finished converting to dry ash storage in 2022. The master plan for site wide ash
management is filed with the MDEQ-AOC8 and additional information on CCRs is
available at Talen's website9. 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 posted
bonds for nearly $6 million in 2018 for cost assurance and an additional $7 million in 2019
related to Units 3 and 4 closure. These amounts are updated annually, increasing as
clean-up plans are finalized and approved in the coming years and then eventually
decreasing as final remediation activities are completed .
Rathdrum
Rathdrum consists of two identical simple-cycle combustion turbine (CT) units. This
natural gas-fired plant located near Rathdrum, Idaho connects to the Avista transmission
system. It entered service in 1995 and has a maximum combined capacity of 176 MW in
the winter and 126 MW in the summer. The nameplate rating is 166.5 MW. Chapter 6,
Supply-Side Resource Options, provides details about modernization options under
consideration at Rathdrum.
Northeast
The Northeast plant, located in Spokane, has two identical aero-derivative simple-cycle
CT units completed in 1978. The plant can burn natural gas and oil, but 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 61.8 MW. The plant air
permit limits run hours to 100 hours per year, limiting its use primarily to reliability events.
Avista assumes this plant will retire in 2035 for modeling purposes of this IRP.
Boulder Park
The Boulder Park project entered service in the Spokane Valley in 2002. It connects
directly to the Avista transmission system. The site uses six identical natural gas-fired
internal combustion reciprocating engines to produce a combined maximum capacity and
nameplate rating of 24.6 MW. Avista assumes this plant will retire in 2040 for modeling
purposes of this IRP.
8 http://deq.mt.gov/DEQAdmin/mfs/ColstripSteamElectricStation0
9 https://www.talenenergy.com/ccr-colstrip/.
Avista Corp 2023 Electric IRP 3-7
Chapter 3: Existing Supply Resources
Coyote Springs 2
Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine (CCCT)
located near Boardman, Oregon. The plant connects to the BPA 500 kV transmission
system under a long-term agreement. The plant began service in 2003 and has a
maximum capacity of 317.5 MW in the winter and 285 MW in the summer with duct
burners operating. The nameplate rating of the plant is 287.3 MW.
Kettle Falls Generation Station and Kettle Falls Combustion Turbine
The Kettle Falls Generating Station entered service in 1983 near Kettle Falls,
Washington. It is among the largest biomass generation plants in North America and
connects to Avista on its 115 kV transmission system. The open-loop steam plant uses
waste wood products (hog fuel) from area mills and forest slash but can also burn natural
gas on a limited basis. A 7.5 MW combustion turbine (CT), added to the facility in 2002,
burns natural gas and increases overall plant efficiency by sending exhaust heat to the
wood boiler when operating in combined-cycle mode.
The wood-fired portion of the plant has a maximum capacity of 50 MW and a nameplate
rating of 50.7 MW. Varying fuel moisture conditions at the plant causes correlated
variation between 45 and 50 MW. The plant's capacity increases from 55 to 58 MW when
operated in combined-cycle mode with the CT. The CT produces 8 MW of peaking
capability in the summer and 11 MW in the winter. The CT can be limited in the winter
when the natural gas pipeline is capacity constrained. The CT is not available when
temperatures fall below zero.10 This operational assumption reflects natural gas
availability limits in the area.
As part of the 2022 All-Source Request for Proposals (RFP), an upgrade to the facility
was selected as a cost-effective option to serve customers. A memo of understanding
was signed with Myno Carbon ("Myno") who will provide Kettle Falls with steam from a
biochar process. This steam adds 13 MW11 of generation capability beginning in 2026 for
a total capacity of 63 MW (net). Myna's process will use a portion of the wood fuel supply
to create biochar for the agriculture industry and Avista will purchase the steam by by­
product for power production. In total, the production increase at Kettle Falls will be 11
MW when accounting for energy consumed by Myno. Avista customers will benefit from
this arrangement by increasing capacity, lowering production costs, and lowering air
emissions related to wood combustion at Kettle Falls.
10 Avista is reviewing its policies and may restrict the CT use when the pipeline is at lower pressures then
the current standard. This change could further restrict the plant from producing power in winter months.
For this IRP, Avista assumes no winter Kettle Falls CT capacity after 2023.
11 As part of the change in generation the total steam production will be 18 MW.
Avista Corp 2023 Electric IRP 3-8
Chapter 3: Existing Supply Resources
Small Avista-Owned Solar
Avista operates three small solar projects. The first solar project is three kilowatts located
at its corporate headquarters as part of its former Solar Car initiative. Avista installed a
15 kilowatt solar system in Rathdrum, Idaho to supply its My Clean Energy™ (formerly
Buck-A-Block) voluntary green energy program. The 423-kW Avista Community Solar
project, located at the Boulder Park property, began service in 2015.
Table 3.5: Avista-Owned Solar Resource Capability
Rathdrum Solar Rathdrum, ID
Boulder Park Solar S okane Valle , WA
Total 441
Power Purchase and Sale Contracts
Avista uses purchase and sale arrangements of varying lengths to meet a portion of its
load requirements. These contracts provide many benefits by adding environmentally
low-impact generation from low-cost hydro and wind power to the Company's resource
mix. This section describes the contracts in effect during the timeframe of the 2023 IRP.
Tables 3.4 through 3.6 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 project financing by providing a market
for the surplus power. The contract terms obligate the PUDs to deliver power to Avista
points of interconnection. Avista originally entered long-term contracts for the output of
five projects "at cost". Avista now competes in capacity auctions to retain the rights of
these contracts as they expire. The Mid-Columbia contracts in Table 3.6 provide clean
energy, capacity, and reserve capabilities.
The timing of the power received from the Mid-Columbia projects is a result of agreements
including the 1961 Columbia River Treaty and the 1964 Pacific Northwest Coordination
Agreement (PNCA). Both agreements optimize hydroelectric project operations in the
Northwest U.S. and Canada. In return for these benefits, Canada receives return energy
under the Canadian Entitlement. The Columbia River Treaty and the PNCA manage
storage water in upstream reservoirs for coordinated flood control and power generation
optimization. The Columbia River Treaty may end on September 15, 2024. Studies are
underway by U.S. and Canadian entities to determine possible post-2024 Columbia River
operations. Federal agencies are soliciting feedback from stakeholders and ongoing
negotiations will determine the future of the treaty. This plan does not model alternative
outcomes for treaty negotiations.
Avista Corp 2023 Electric IRP 3-9
Chapter 3: Existing Supply Resources
Table 3.6: Mid-Columbia Capacity and Energy Contracts12
Counter Project(s) Percent Start Date End Date On-Peak Annual Canadian
Party Share Capability Energy Entitle-
(%) (MW) (aMW) ment
Grant Priest Rapids/ 3.76 Dec-2001 Dec-2052 74.9 38.4 -2.1
PUD Wanapum
Chelan Rocky Reach/ 5.0 Jan-2016 Dec-2030 87.5 52.4 -2.7
PUD Rock Island
Chelan Rocky Reach/ 5.0 Jan-2024 Dec-2033 87.5 52.4 -2.7
PUD Rock Island
Chelan Rocky Reach/ 5.0 Jan-2026 Dec-2030 87.5 52.4 -2.7
PUD Rock Island
Chelan Rocky Reach/ 10.0 Jan-2031 Dec-2045 174.9 104.8 -5.4
PUD Rock Island
Douglas Wells 2.7613 Oct-2018 Dec-2028 23.8 12.2 -6.2
PUD
Columbia Basin Hydro
In December 2022, Avista reached an agreement to purchase the entire output from
Columbia Basin Hydro's irrigation generation fleet through 2045. The agreement includes
all generation and environmental attributes from seven hydroelectric projects totaling
146.3 MW of capacity. Avista will take delivery of projects over time as existing contracts
with other utilities expire. Table 3.7 outlines the project delivery timeline, capacity, and
energy deliveries. These projects are unique as they are based on the amount of irrigation
used by central Washington farmers from March through October, with most of the
generation occurring in May through August in a consistent firm energy delivery. This
summer capacity solves the Avista's future summer capacity needs consequently, less
solar is selected in the preferred resource strategy.
Table 3.7: Columbia Basin Hydro Projects
Project Name Start Date Capacity (MW) Energy (aMW)
Russell D. Smith 1/1/2023 6.1 1.5
EBC 4.6 5/1/2023 2.2 0.9
Summer Falls 1/1/2025 94.0 41.4
PEC 66 3/1/2025 2.4 0.5
Quincy Chute 10/1/2025 9.4 3.6
Main Canal 1/1/2027 26.0 11.6
PEC Headworks 9/1/2030 6.2 2.3
Total 146.3 61.8
12 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 3.5 are presumed and
planned to be integrated via Avista's interconnection(s) to the Mid-Columbia region.
13 Percent share varies each year depending on Douglas PU D's load growth. Avista and Douglas PUD also
have an exchange agreement through 2023 where Avista delivers 47 MW in exchange for 10% of the Wells
project.
Avista Corp 2023 Electric IRP 3-10
Chapter 3: Existing Supply Resources
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, or Qualifying
Facility energy purchase contracts, shown in Table 3.8 accumulating to 139.9 MW, but
fully net metered from customer load are shown in Table 3.9 for a total of 1.47 MW, power
from these facilities is only purchased if generation exceeds load. The IRP assumes
renewal of these contracts after current terms end based on Avista's experience with
these contracts and ongoing communications with the project owners. Avista takes the
energy as produced, does not control the output of any PURPA resources and does not
receive the RECs from these projects. However, the Washington-based PURPA projects
reduce the amount of load that needs to be met for CETA compliance.
Table 3.8: PURPA Agreements
Contract Fuel Source Location Contract Size 5 year
End Date (MW) avg. Gen.
History
(aMW)
Meyers Falls Hydro Kettle Falls, WA 12/2025 1.30 1.18
Spokane Waste to Energy Waste Spokane, WA 12/2037 22.70 13.85
Plummer Saw Mill Wood Waste Plummer, ID 12/2023 5.80 4.07
Deep Creek Hydro Northport, WA 12/2032 0.41 0.02
Clark Fork Hydro Hydro Clark Fork, ID 12/2037 0.22 0.11
Upriver Dam14 Hydro Spokane, WA 12/2037 14.50 4.95
Biq Sheep Creek Hydro Hydro Northport, WA 6/2025 1.40 0.82
Ford Hydro LP Hydro Weiooe, ID 6/2024 1.41 0.44
John Day Hydro Hydro Lucile, ID 9/2041 0.90 0.30
Phillips Ranch Hydro Northport, WA n/a 0.02 0.00
City of Cove Hydro Cove, OR 10/2038 0.80 0.35
Clearwater Paper Biomass Lewiston, ID 12/2023 90.20 52.02
Total 139.92 78.11
Table 3.9: PURPA Agreements (net meter only)
U of Idaho Steam Plant Moscow, ID 2/2042 0.74
U of Idaho Solar Solar Moscow, ID 2/2042 0.03
Total 0.96
14 Energy estimate is net of the City of Spokane's pumping load.
Avista Corp 2023 Electric IRP 3-11
Chapter 3: Existing Supply Resources
Lancaster
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 SPA 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 fuel needs of
the plant.
The Lancaster resource was bid into Avista's 2022 All-Source RFP and was selected as
a least cost resource through third-party evaluation. This agreement extends the existing
agreement through December 31, 2041 .
Palouse Wind
Avista signed a 30-year PPA in 2011 with Palouse Wind for the entire output of its 105
MW project starting in December 2012 . The project directly connects to Avista's
transmission system between Rosalia and Oaksdale, Washington in Whitman County.
Rattlesnake Flat Wind
Rattlesnake Flat was selected as the preferred project in Avista's 2018 RFP for 50 aMW
of renewable energy. It is a 160.5 MW (limited by transmission constraints to 144 MW)
20-year PPA with an expected net annual output of 469,000 MWh (53.5 aMW). Located
east of Lind, Washington in Adams County, the project went online in December 2020.
30-Year Wind PPA
In January 2023 , Avista reached an agreement to acquire approximately 100 MW of wind
energy through a 30-year purchase power agreement. Avista will provide more
information once both parties agree to make the project public.
Adams-Nielson Solar
Avista signed a 20-year PPA for the Adams-Nielson solar project in 2017. The 80,000
panel, single axis, solar facility can deliver 19.2 MW of alternating current (AC) power and
entered service in December 2018. The project is located north of Lind, Washington in
Adams County. The project provides energy for Avista 's Solar Select program. Solar
Select allows commercial customers to voluntarily purchase through 2028. The solar
energy attributes from the project for these customers are at no additional cost through a
combination of tax incentives from the State of Washington and offsetting power supply
expenses.
Sales Contracts
Avista has intermediate power sales contracts used to optimize Avista's energy position
on behalf of customers. Avista currently has three sales contracts extending through
2023. These contracts include the Nichols Pumping sale of power at Colstrip; Douglas
PUD, an exchange agreement tied to the 10% purchase of the Wells hydro project; and
the Morgan Stanley contract to facilitate the sale of Clearwater Paper's generation. For
resource planning purposes, Avista does not assume contract sale extensions. Table
3.10 describes Avista's other contractual rights and obligations.
Avista Corp 2023 Electric IRP 3-12
Chapter 3: Existing Supply Resources
Table 3.10: Other Contractual Rights and Obligations
Contract Type Fuel Source End Winter Summer Annual
Date Capacity Capacity Energy
Contri-Contri-(aMW)
bution bution
(MW) (MW)
Lancaster Purchase Natural Gas 2041 283.0 231 .0 218.0
Palouse Purchase Wind 2042 5.3 5.3 36.2
Rattlesnake Flat Purchase Wind 2040 7.2 7.2 53.5
A s-i son urchase Solar 20 8 0.4 10.2 5.6
Nichols Pum in Sale S stem 202315 -5.0 -5.0 -5.0
Morgan Stanley Sale Clearwater 2023 -46.0 -46.0 -44.9
Pa er
Dou las PUD Sale S stem 2023 -48.0 -48.0 -48.0
Total 196.9 154.7 215.4
Natural Gas Pipeline Rights
Avista transports natural gas to its natural gas-fired generators using the GTN pipeline
owned by TC Energy (formally TransCanada). The pipeline runs between Alberta,
Canada and the California/Oregon border at Malin. Avista holds 60,592 dekatherms per
day of capacity from Alberta to Stanfield, but in November 2023, the capacity rights will
increase to 69,989 dekatherms. Avista controls another 26,388 dekatherms per day from
Stanfield to Malin. Figure 3.4 below illustrates Avista's natural gas pipeline rights. This
figure includes the theoretical capacity if the plants under Avista's control run at full
capacity for the entire 24 hours in a day on the system. The maximum burn by Avista is
1,442,413 dekatherms per day based on the average of the top five historical natural gas
burn days of 2019, 2022 and 2023, as shown in Table 3.11.
As discussed above, Avista does not have firm transportation rights for the entirety of its
natural gas generation capacity. Avista relies on short-term transportation contracts to
meet needs above Avista's firm contractual rights . Adequate surplus transportation has
historically been available because the GTN pipeline was not fully subscribed. Natural
gas producers have recently purchased all remaining rights on the system to transport
their supply south and take advantage of higher prices in the U.S. compared to Canada.
However, these suppliers do not appear to have firm off-takers of their product, and
therefore a lack of transportation likely will not lead to a lack of fuel for Avista's natural
gas plants. This becomes a pricing issue rather than a supply issue when suppliers control
the pipeline. Avista will continue acquiring natural gas delivery beyond its firm rights
through the daily market. When the market begins to tighten, or if the premiums paid for
delivery through suppliers increases greatly, Avista will revisit its options. These options
include procurement through pipeline capacity expansions and investment in onsite fuel
storage.
15 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.
Avista Corp 2023 Electric IRP 3-13
Chapter 3: Existing Supply Resources
Table 3.11: Top Five Historical Peak Day Natural Gas Usage (Dekatherms)
Date Boulder Coyote Lancaster Rathdrum GTN Firm
Park Springs 2 Total Rights
3/2/2019 5,361 45,855 48,889 43,614 143,719 60,592
10/18/2022 5,491 48,938 45,611 42,067 142,107 60,592
11/10/2022 5,401 50,371 46,700 40,305 142,777 60,592
12/21/2022 5,505 50,591 43,826 43,898 143,819 60,592
1/30/2023 4,571 51 ,567 48,206 44,441 148,785 60,592
Figure 3.4: Avista Firm Natural Gas Pipeline Rights
Pipeline Capacity
60,592 DTh/Day
Avista Corp
Coyote Springs
53,550 DTh/Day
2023 Electric IRP
Lancaster
Rathdrum
Boulder
49,000
43,600
5,400
98,000 DTh/Day
Pipeline Capacity
26,388 DTh/Day
3-14
Chapter 3: Existing Supply Resources
Resource Environmental Requirements and Issues
Electricity generation creates environmental impacts subject to regulation by federal,
state, and local authorities. The generation, transmission, distribution, service, and
storage facilities Avista has ownership interests in are designed, operated, and monitored
to maintain compliance with applicable environmental laws. Avista conducts periodic
reviews and audits of its facilities and operations to ensure continued compliance. To
respond to or anticipate emerging environmental issues, Avista monitors legislative and
regulatory developments at all levels of government for environmental issues, particularly
those with the potential to impact the operation and productivity of Avista's generating
plants and other assets.
Generally, environmental laws and regulations have the following impacts while
maintaining and enhancing the environment:
• Increase operating costs of generation;
• Increase the time and costs to build new generation;
• Require modifications to existing plants;
• Require curtailment or retirement of generation plants;
• Reduce the generating capability of plants;
• Restrict the types of plants that can be built or contracted with ;
• Creates resource adequacy challenges;
• Require construction of specific types of generation at higher cost; and
• Increase the cost to transport and distribute natural gas.
The following sections describe applicable environmental regulations in more detail.
Clean Air Act (CAA)
The CAA is a federal law setting requirements for thermal generating plants. States are
typically authorized to implement CAA permitting and enforcement. States have adopted
parallel laws and regulations to implement the CAA. Some aspects of its implementation
are delegated to local air authorities. Colstrip, Coyote Springs 2, Kettle Falls, and
Rathdrum CT all require CAA Title V operating permits. Boulder Park and the Northeast
CT require minor source permits or simple source registration permits to operate. These
requirements can change as the CAA or other regulations change and agencies review
and issue new permits. Several specific regulatory programs authorized under the CAA
impact Avista's generation, as reflected in the following _sections.
Hazardous Air Pollutants (HAPs)
On April 16, 2016, the Mercury Air Toxic Standards (MATS), an EPA rule under the CAA
for coal and oil-fired sources, became effective for all Colstrip units. Colstrip performs
quarterly compliance assurance stack testing to meet the MATS site-wide limitation for
Particulate Matter (PM) emissions (0.03 lbs./MMBtu) a measure used as a surrogate for
all HAPs.
On May 22, 2020, EPA published its reconsideration of the "appropriate and necessary"
finding and concluded that it is not "appropriate and necessary" to regulate electric utility
Avista Corp 2023 Electric IRP 3-15
Chapter 3: Existing Supply Resources
steam generation units under section 112 of the CAA. EPA also took final action on the
residual risk and technology review that is required by CAA section 112 and determined
that emissions from HAP have been reduced such that residual risk is at acceptable
levels. There are no developments in HAP emission controls to achieve further cost­
effective reductions beyond the current standards and, therefore, no changes to the
MATS rule are warranted .
Montana Mercury Rule
Montana established a site wide Mercury cap in 2010, requiring Mercury to be below 0.9
lbs. per trillion Btu. Colstrip installed a mercury oxidizer/sorbent injection system to
comply with the cap. The Montana Department of Environmental Quality (MDEQ) recently
reviewed the equipment and concurred with the plant's assessment that units 3 and 4
operate at 0.8 lb. per Tbtu range. There are no indication mercury requirements will
change in the planning horizon.
Regional Haze Program
EPA set a national goal in 1999 to eliminate man-made visibility degradation in national
parks and wilderness areas by 2064. Individual states must take actions to make
"reasonable progress" through 10-year plans, including application of Best Available
Retrofit Technology (BART) requirements. BART is a retrofit program applied to large
emission sources, including electric generating units built between 1962 and 1977. In the
absence of state programs, EPA may adopt Federal Implementation Plans (FIPs). On
September 18, 2012 , EPA finalized the Regional Haze FIP for Montana. In November
2012, several groups petitioned the U.S. Court of Appeals for the Ninth Circuit for review
of Montana's FIP. The Court vacated portions of the Final Rule and remanded back to
EPA for further proceedings on June 9, 2015. MDEQ is in the process of retaking control
of the program from EPA after issuing a Regional Haze Program progress plan for
Montana in 2017 and Montana's second planning period for regional haze to EPA on
August 10, 2022. A combination of LoNOx burners, overtire 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 does not anticipate additional NOx pollution controls for Colstrip.
Coal Ash Management/Disposal
In 2015, EPA issued a final rule on coal combustion residuals (CCRs), also known as
coal combustion byproducts or coal ash . The rule has been subject to ongoing litigation .
In August 2018, the D.C. Circuit struck down provisions of the rule. The rule includes
technical requirements for CCR landfills and surface impoundments under Subtitle D of
the Resource Conservation and Recovery Act, the nation's primary law for regulating solid
waste. The Colstrip owners developed a multi-year compliance plan to address the CCR
requirements and existing state obligations expressed largely through a 2012
Administrative Order on Consent (AOC). These binding state-issued 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
Avista Corp 2023 Electric IRP 3-16
Chapter 3: Existing Supply Resources
anticipated closure and remediation obligations. The amount of financial assurance
required may vary due to the uncertainty associated with remediation activities. Please
refer to the Colstrip section for additional information on the AOC/CCR related activities.
Particulate Matter (PM)
Particulate Matter (PM) is the term used for a mixture of solid particles and liquid droplets
found in the air. Some particles, such as dust, dirt, soot, or smoke, are large or dark
enough to see with the naked eye. Others are so small they are only detectable with an
electron microscope. Particle pollution includes:
• PM10: inhalable particles, with diameters that are generally 10 micrometers and
smaller; and
• PM2.s: fine inhalable particles, with diameters generally 2.5 micrometers and
smaller.
There are different standards for PM10 and PM2.s. Limiting the maximum amount of PM
to be present in outdoor air protects human health and the environment. The CAA
requires EPA to set National Ambient Air Quality Standards (NAAQS) for PM, as one of
the six criteria pollutants considered harmful to public health and the environment. The
law also requires periodic EPA reviews of the standards to ensure that they provide
adequate health and environmental protection and to update standards as necessary.
Avista owns and/or has operational control of the following generating facilities that
produce PM: Boulder Park, Colstrip, Coyote Springs 2, Kettle Falls, Lancaster, Northeast
and Rathdrum. Table 3.12 below shows each of the plants, status of the surrounding area
with NAAQS for PM2.s and PM10, operating permit, and PM pollution controls.
Appropriate agencies issue air quality operating permits. These operating permits require
annual compliance certifications and renewal every five years to incorporate any new
standards including any updated NAAQS status.
Threatened and Endangered Species and Wildlife
Several 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 its Clark Fork hydroelectric project under a comprehensive
settlement agreement. The restoration of native salmonid fish, including bull trout, is a
key part of the agreement. The result is a collaborative native salmonid restoration
program with the U.S. Fish and Wildlife Service, Native American tribes and the states of
Idaho and Montana, consistent with requirements of Avista's FERC license.
Various statutory authorities, including the Migratory Bird Treaty Act, have established
penalties for the unauthorized take of migratory birds. Some of Avista's facilities can pose
risks to a variety of such birds so avian protection plans are followed for these facilities.
Avista Corp 2023 Electric IRP 3-17
Chapter 3: Existing Supply Resources
Table 3.12: Avista Owned and Controlled PM Emissions
Thermal PM2.s PM10 Air Operating PM Pollution Controls
Generating NAAQS NAAQS Permit
Station Status Status
Boulder Park Attainment Maintenance Minor Source Pipeline Natural Gas
Colstrip Attainment Non-Major Source Fluidized Bed Wet Scrubber
Attainment Title V OP
Coyote Springs Attainment Attainment Major Source Pipeline Natural Gas, Air
2 Title V OP filters
Kettle Falls Attainment Attainment Major Source Multi-clone collector,
Title V OP Electrostatic Precipitator
Lancaster Attainment Attainment Major Source Pipeline Natural Gas, Air
Title V OP filters
Northeast Attainment Maintenance Minor Source Pipeline Natural Gas, Air
filters
Rathdrum Attainment Attainment Major Source Pipeline Natural Gas, Air
Title V OP filters
Climate Change -Federa l Regulatory Actions
In June 2019, the EPA released the final version of the Affordable Clean Energy (ACE)
rule, the replacement for the Clean Power Plan (CPP). The final ACE rule combined three
distinct EPA actions. First, EPA finalized the repeal of the CPP. The CPP was comprised
of three "building blocks" identified by the EPA as follows:
• Reducing CO2 emissions by undertaking efficiency projects at affected coal-fired
power plants (i.e., heat-rate improvements);
• Reducing CO2 emissions by shifting electricity generation from affected power
plants to lower-emitting power plants (e.g ., natural gas plants); and
• Reducing CO2 emissions by shifting electricity generation from affected power
plants to new renewable energy generation.
Notably, the second and third building blocks, responsible for the majority of projected
emission reductions, were premised on "beyond the fence" measures to reduce
emissions. Second, the EPA finalized the ACE rule, comprising the EPA's determination
of the Best System of Emissions Reduction (BSER) for existing coal-fired power plants
and procedures to govern States' promulgation of standards of performance for such
plants within their borders. EPA set the final BSER as heat rate efficiency improvements
based on a range of "candidate technologies" to be applied to a plant's operating units
and requires each State to determine application to each coal-fired unit based on
consideration of remaining useful plant life. Contrary to the CPP, ACE relied solely on
emission reductions from the specific source, or "inside the fence." Lastly, the ACE rule
included implementing regulations for State plans.
In January 2021, the U.S. Court of Appeals for the District of Columbia Circuit (D.C.
Circuit) vacated the ACE Rule and remanded the record back to the EPA for further
consideration consistent with its opinion, finding that the EPA misinterpreted the CAA
Avista Corp 2023 Electric IRP 3-18
Chapter 3: Existing Supply Resources
when it determined that the language of Section 111 barred consideration of emissions
reduction options that were not applied at the source. The Court also vacated the repeal
of the CPP. On May 11, 2023, the EPA issued draft rules regarding large stationary coal
and natural gas fired resources. Avista is awaiting final rules prior to making any
adjustments to its resource plan.
Climate Change -State Legislation and State Regulatory Activities
Washington State enacted Senate Bill 5116, CETA. As stated elsewhere in this IRP,
CETA aims to reduce greenhouse gas emissions from specific sectors of the economy
through direct regulation including electricity generation. CETA requires utilities to
eliminate coal-fired resources from Washington retail rates by the end of 2025, achieve
carbon neutrality by 2030 with no more than 20% of load met by alternative compliance
means, and serve all retail load with renewable and non-emitting resources by 2045.
Washington and Oregon apply greenhouse gas emissions performance
standards (EPSs) to electric generation facilities used to serve retail loads in their
jurisdictions, whether the facilities are located within those respective states or
elsewhere. The EPS prevents utilities from constructing or purchasing generation
facilities or entering into power purchase agreements of five years or longer duration to
purchase energy produced by plants that, in any case, have emission levels higher than
1,100 CO2 equivalency (CO2e) pounds per MWh. The Washington State Department of
Commerce reviews this standard every five years. The last review was completed in
September 2018 where it adopted a new rate of 925 pounds CO2e per MWh.
Energy Independence Act (EIA)
The EIA in Washington requires electric utilities with over 25,000 customers to acquire
qualified renewable energy resources and/or renewable energy credits equal to 15% of
the utility's total retail load in Washington in 2020 and beyond. Utilities under EIA
regulation must also meet biennial energy conservation targets. Failure to comply with
renewable energy and efficiency standards result in penalties of as much as $50 per MWh
plus inflation since 2006 of deficiency. Avista meets the requirements of the EIA through
a combination of hydro upgrades, wind, biomass, and renewable energy credits.
Beginning in 2030, if a utility is compliant with CETA, the utility is deemed to meet the
requirements of the EIA.
Washington Climate Commitment Act
The Washington legislature passed its largest environmental program in 2021, the
Climate Commitment Act (CCA). This act creates a state-wide emissions cap and trade
program where emissions are to be reduced by 95% by 2050 for all industries. Beginning
in 2023, entities will be required to cover their emissions by the purchase of "allowances"
acquired through state auction or by purchasing offsets. Electric utilities are required to
offset their emissions but will be given free allowances to cover most of their emissions.
The full impacts of the CCA are not known at this time. The intent of this legislation allows
for the Washington State program to join California and the Quebec markets to increase
"allowance" liquidity possibly as early as 2025. California and Quebec still need to
approve the addition of Washington to their program. The law also focuses on using
Avista Corp 2023 Electric IRP 3-19
Chapter 3: Existing Supply Resources
proceeds from state allowance auctions to improve over-burdened communities and
tribes, but also incent a clean energy transformation of Washington to electrify
transportation and heating.
Avista Corp 2023 Electric IRP 3-20
Chapter 4: Long-Term Position
4. Long-Term Position
Avista plans its resource portfolio to meet multiple long-term objectives including serving
peak loads, providing operational and planning reserves, meeting monthly energy needs,
and meeting clean energy goals established in Washington State law as well as other
applicable policies. This chapter presents the long-term load and resource position at the
end of 2022 and includes resources acquired from the 2022 All-Source Request for
Proposals (RFP). Notwithstanding future resource changes, there are several
fundamental changes to Loads & Resources (L&R) since the 2021 IRP. The following
developments have occurred since the 2021 IRP:
• Additional long-term capacity and energy acquired from Chelan PUD, Columbia
Basin Hydro, a 30-year wind Power Purchase Agreement (PPA), and plans to
upgrade Kettle Falls Generating Station and Post Falls;
• The Lancaster PPA is extended through 2041;
• The Western Power Pool's (WPP) Western Resource Adequacy Program (WRAP)
entered the first stage of non-binding program implementation and its program
metrics now guide some of Avista's resource adequacy planning;
• Future temperature changes are incorporated into Avista 's base hydro and load
forecast;
• Risk planning including variability of hydro, wind, solar, and load for monthly
energy planning ; and
• Near term clean energy targets from Avista's Clean Energy Implementation Plan
(CEIP) are approved.
Section Highlights
• Avista's Planning Reserve Margin requirement is 22% in the Winter and 13% in
the summer until the WRAP is a binding program.
• Avista's first capacity and energy resource deficiency begins in January 2034.
• The WRAP's qualifying capacity credits (QCCs) are used for Avista's resource
capacity position.
• Avista has sufficient clean energy resources to meet its projected Washington's
Clean Energy Transformation Act (CETA) targets through 2033 under normal
conditions.
Capacity Requirements
Avista must plan its resource portfolio to have the capacity to reliably meet system
demand at any given time. Significant uncertainty is inherent in this exercise due to
situations when load exceeds the forecast and/or resource output falls below expectations
due to adverse weather, forced outages, poor water conditions , variability in wind and
solar output or other unplanned events. Utilities plan to have more generating capacity,
called a planning reserve margin, than is required to address this uncertainty and meet
forecasted peak demand.
Avista Corp 2023 Electric IRP 4-1
Chapter 4: Long-Term Position
Reserve margins, on average, increase customer rates when compared to resource
portfolios without reserves because of the extra cost of carrying rarely used generating
capacity. Traditionally, reserve resources have the physical capability to generate
electricity, but most have high operating costs limiting normal dispatch and revenue.
Therefore, a balance must be achieved between having capacity to address any
eventuality and the cost to carry the unused capacity.
Prior to the development of the WRAP, there was no Northwest energy 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% for predominately thermal systems and 10% for predominately
hydro systems, 1 but does not provide an estimate for energy-limited hydro systems like
Avista's.
In the prior IRPs, Avista used a planning reserve margin of 16% in the winter months and
7% in the summer months.2 Those margins were derived from a study of resources and
loads using 1,000 simulations of varying weather for loads and thermal generation
capability, forced outage rates on generation, water conditions for hydro plants and wind
generation. The reserve margins ensure Avista's system could meet all expected load in
95% of the simulations, or a 5% loss of load probability (LOLP). Avista then included
operating reserves in addition per Western Electric Coordinating Council (WECC)
requirements, Avista must maintain 3% for balancing of area load and 3% for on-line
balancing area generation. Within this quantity, 30 megawatts must also qualify as
Frequency Response Reserve (FRR). Avista must also maintain reserves to meet load
following and regulation requirements of within-hour load and generation variability
equivalent to 16 MW at the peak hour. The combination of operating, load following, and
planning reserves resulted in a total reserve margin of 24.6% in the winter months and
15.6% in the summer months.
To align its planning reserve margin (PRM) with the WRAP methodologies, Avista
simplified its approach for this IRP. First Avista now uses a 22% PRM in the winter and a
13% in the summer for this IRP. In addition to these values Avista also includes an
adjustment to cover regulation and reserves for non Avista loads and resources within
the balancing area. This amount equals approximately 21 MW in the winter and 20 MW
in the summer and escalates with load growth. In addition to these changes to the PRM,
Avista also is using the WRAP's methodology for resource capacity accounting, also
known as Qualifying Capacity Credit (QCC). The combination of the new QCC values
and the new PRM values effectively do not change the Avista planning requirements from
the 2021 IRP net position. This is due to the QCC values for resources lowering the
amount of capacity as compared to Avista's prior methodology.
Western Resource Adequacy Program
In response to the growing penetration of renewable variable energy resources and
retirements of thermal generation in the West, the WPP initiated an effort in 2019 to
1 http://www.nerc.com/pa/RAPA/ri/Pages/PlanningReserveMargin.aspx.
2 Excludes operating reserves and other flexibility requirements
Avista Corp 2023 Electric IRP 4-2
Chapter 4: Long-Term Position
understand capacity issues in the region and identify potential solutions. The product of
these efforts is the WRAP. The purpose of the WRAP is to leverage diversity of loads and
generation throughout the WECC so individual entities do not need to carry the full burden
of supplying adequate capacity for their systems. The FERC filing to establish a tariff for
the WRAP describes the program as follows:
The WRAP leverages the existing bilateral market structure in the West to
develop a resource adequacy construct with two distinct aspects: (1) a
Forward Showing Program through which WPP forecasts Participants' peak
load and establishes a Planning Reserve Margin ("PRM'? based on a
probabilistic analysis to satisfy a loss of load expectation ("LOLE'? of not more
than one event-day in ten years, and Participants demonstrate in advance that
they have sufficient qualified capacity resources (and supporting transmission)
to serve their peak load and share of the PRM; and (2) a real-time Operations
Program through which Participants with excess capacity, based on near-term
conditions, are requested to "holdback" capacity during critical periods for
potential use by Participants who lack sufficient resources to serve their load
in real-time.
The WRAP is a voluntary resource adequacy planning and compliance framework where
program participants voluntarily join, but once committed are obligated to comply with
requirements or be fined for non-compliance. The program is in the first phase of
implementation with the initiation of a non-binding Forward Showing Program in Winter
2022/2023 and Summer 2023.3
To demonstrate compliance with the Forward Showing Program , participants must
demonstrate its QCCs for resources and contracts are equal to or greater than peak
demand less demand response programs plus the assigned monthly planning reserve
margin. Load, hydro and renewable output, thermal resource capacity, forced outage
data, and planned outage schedules are provided to the program operator who then
provides QCC values for specific resources and an assigned peak load.
Metrics for the winter and summer Forward Showing Program for 2022 and 2023 have
been established and are shown in Table 4.1 . Avista has sufficient capacity to meet the
requirements of the WRAP Forward Showing Program in the first non-binding period.
3 Winter forward showing period starts in November 2022.
Avista Corp 2023 Electric IRP 4-3
Chapter 4: Long-Term Position
Table 4.1: Avista 2023 Summer and 2023-2024 Winter Metrics (MW)
Month Planning Total Total Surplus/Deficient
Reserve Margin Obligation Portfolio QCC Capacity
Nov-22 21.6% 1,770 2,081 311
Dec-22 17.7% 1,882 2,184 302
Jan-23 19.0% 1,944 2,287 343
Feb-23 19.9% 1,911 2,347 436
Mar-23 26.9% 1,844 2,346 502
Jun-23 16.5% 1,696 2,165 469
Jul-23 10.4% 1,801 2,140 339
Auq-23 10.3% 1,836 2,098 262
Sep-23 17.9% 1,590 2,111 521
Interim Capacity Planning Methodology
Avista joined the WRAP to address capacity risk at a regional level rather than at a utility
scale and provide a framework for each utility to contribute a proportionate share to
address regional capacity needs. Planning required to be a WRAP participant addresses
risks such as variability in peak load resulting from differing weather conditions and
variation in demand-side resources penetration. Renewable contributions are addressed
by determining the QCC values over the geographic footprint of WRAP participants, and
market availability is addressed by the real-time operations program and minimum PRM
requirements. While the WRAP is in the non-binding phase, Avista will keep higher
planning reserve margins than those required by the WRAP since the WRAP planning
reserve margin is based on all utilities participating in the sharing program meeting the
forward showing program requirements.
The Northwest Planning and Conservation Council (NPCC) is also evaluating the creation
of new resource adequacy metrics beyond traditional Loss of Load Probability
Expectation (LOLE). These metric covers frequency, duration, and magnitude of outages.
Avista will follow this process to see if it should develop a metric beyond what is required
in the WRAP.
Using the PRM and QCC methodologies previously discussed in this chapter, Figure 4.1
presents the winter one-hour peak capacity load and resources balance, and Figure 4.2
presents the summer one-hour peak capacity load and resources balance. Starting in
2034 there is a winter capacity need and starting in 2036 there is a summer capacity
need. The deficiencies increase over the planning horizon due to load growth, resource
retirements and contract expirations.
Avista Corp 2023 Electric IRP 4-4
Ill --ca 3 ca C')
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Chapter 4: Long-Term Position
Figure 4.1: Winter One-Hour Peak Capacity Load and Resources Balance
3,000
2,500
2,000
1,500
1,000
500
0
-Total Resources
--Obligations (Peak Load+ PRM + operating reserves)
0 M 0 N
.... M 0 N
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"' M 0 N
"' M 0 N
,.._
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Figure 4.2: Summer One-Hour Peak Capacity Load and Resources Balance
3,000
2,500
2,000
1,500
1,000
500
0
,:t "' N N 0 0 N N
-Total Resources
Obligations (Peak Load+ PRM + operating reserves)
"' N 0 N
,.._
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Avista Corp 2023 Electric IRP 4-5
Chapter 4: Long-Term Position
Energy Requirements
In contrast to peak planning, energy planning determines the need based on customer
demand with a time element. Avista evaluates energy planning on a monthly target basis
for meeting customer demand, renewable targets, and evaluating generation risks. In
previous IRP's Avista only monitored energy requirements on an annual average basis.
Avista found this methodology worked in the past when traditional thermal unit such as
natural gas generation was the resource choice in IRPs, but with a transition to renewable
energy resources with differing energy delivery time periods, Avista is now using monthly
energy requirements to ensure Avista do not acquire too much energy in certain periods
such as spring and not enough in high load months such as August or January.
The monthly energy analysis requires additional steps beyond capacity planning to take
into account what may happen to a resource's operations. Evaluation of monthly
generation is specific to the resource in question , e.g., the factors impacting hydro
generation are different than the factors impacting thermal generation. This section
compares monthly generation and monthly demand to determine deficit and surplus
conditions for the 2024-2045 period. A discussion of monthly demand is provided in
Chapter 2. Table 4.2 details how monthly generation for each resource type is evaluated.
Table 4.2: Monthly Energy Evaluation Methodologies
Resource Type Evaluation Methodology
Coal Unit capacity reduced by a percentage according to planned and forced
outaqe rates.
Biomass Unit capacity reduced by a percentage according to planned and forced
outaqe rates.
Natural Gas Unit capacity adjusted for monthly ambient average temperature and
Combined Cycle reduced by a percentage according to planned and forced outage rates and
any runtime limitations imposed by operatinq permits.
Natural Gas Unit capacity reduced by a percentage according to planned and forced
Peaker outaqe rates and any runtime limitations imposed by operatinq permits.
Wind Five year monthly average output if available, or average output estimates
provided by facility operator.
Solar Five year monthly average output if available, or average output estimates
provided by facility operator.
Hydro Monthly median generation of the previous 30 years. Future years include
both historical and forecasted monthly qeneration.
There are two important changes in this IRP from previous IRPs:
1. Hydro generation and load both include the predicted impacts of forecasted
temperature changes; and
2. The risk evaluation includes variability in all renewables rather than just variation
in hydro.
Energy Risk Evaluation
Energy planning is based on average conditions. The load forecast utilizes 20-year
average weather while the hydro generation estimates are based on the median over a
Avista Corp 2023 Electric IRP 4-6
Chapter 4: Long-Term Position
30-year period. There is a risk the load can be larger and/or hydro generation can be
lower than forecasted. Additionally, in the last decade, Avista has added wind and solar
generation to its portfolio , both having variable output period to period. To address this
risk Avista adds an energy planning margin to the load and resource balance evaluation .
As with capacity planning, there are no defined methods for establishing an energy
planning margin or contingency adjustment. In prior plans, the energy contingency
adjustment was based on the difference between average load and load at the 90%
confidence interval added to the difference between monthly median hydro generation
and the 10th percentile hydro generation. A new methodology is used for this analysis.
Monthly estimates of load and generation for each hydro, wind, and solar facility for
weather conditions for the period 1948 to 2019 were developed using regression models
of the relationship between weather variables, generation, and load. Total generation was
subtracted from load. Large values occur when load is larger than average and/or
generation is below average. The 95th percentile of the monthly values was subtracted
from the average value. This represents the energy necessary to meet above average
loads during periods of low hydro, wind, and solar production.
Figure 4.3: Comparison of Energy Contingency Methodology
350
300 a Previous Method
□ New Methodology
250
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Avista Corp 2023 Electric IRP 4-7
Chapter 4: Long-Term Position
Net Energy Position
Avista's net energy position is determined by summing all generation rights from Avista
facilities and power purchase agreements and subtracting obligations including
forecasted monthly load, contracted sales, and accounting for the energy contingency.
Table 4.3 presents net monthly energy positions for 2025, 2030, 2035, 2040, and 2045.
Table 4.3: Net Energy Position
Month 2025 2030 2035 2040 2045
January 218 109 35 -3 -829
February 216 76 27 -26 -823
March 375 260 210 168 -603
April 551 427 360 311 -326
May 691 604 540 486 -17
June 737 621 540 447 -175
July 395 240 200 104 -672
August 266 135 59 -8 -766
September 339 222 176 135 -603
October 346 218 148 81 -677
November 261 116 27 -20 -818
December 297 147 69 -17 -851
Forecasted Temperature & Precipitation Analysis
Projected temperature increases will impact hydro generation, natural gas turbine
capacity, and load. The following provides a summary of the analysis completed, results
of the analysis, and a comparison to values used in the 2021 IRP.
The climate analysis is based on data developed for the Columbia River Basin by the
River Management Joint Operating Committee (RMJOC) comprised of the Bonneville
Power Administration (BPA), United States Army Corps of Engineers, and United States
Bureau of Reclamation. The RMJOC, in conjunction with the University of Washington
and Oregon State University, completed two studies, one in 2018 and another in 2020,
utilizing downscaled global climate models (GCMs), hydrology and reservoir operation
models to predict monthly river flows for the period 2020-2100 for locations throughout
the Columbia River Basin, including all Avista's hydroelectric facility locations.
There is significant uncertainty in projecting future temperature and precipitation and the
impact on streamflow and reservoir operations. The RMJOC used an ensemble approach
to capture a range of potential outcomes. The approach used unique combinations of two
representative concentration pathways (RCPs), ten GCMs, three downscaling techniques
and four hydrology models. In total there were 172 unique model combinations resulting
in 172 streamflow datasets for each location . The streamflow data was then used in
reservoir operation models generating monthly flows under current operating parameters
for each of the Columbia Basin hydroelectric facilities. Flow data allows for an estimate
of generation at each of the facilities.
Avista Corp 2023 Electric IRP 4-8
Chapter 4: Long-Term Position
Given the sheer volume of data, a method to select a representative set from the 172
modeling combinations was needed. Fortunately, BPA conducted this exercise and
selected a subset of modeling combinations representing a sufficient cross section of
outcomes to calculate generation . The subset represents 19 modeling combinations for
both RCP 4.5 and RCP 8.5.
RCPs represent different greenhouse gas (GHG) emission scenarios varying from no
future GHG reductions to significant GHG reductions. The Intergovernmental Panel on
Climate Change (IPCC) describes the scenarios as follows:
• RCP 2.6 -stringent mitigation scenario
• RCP 4.5 & RCP 6.0 -intermediate scenarios
• RCP 8.5 -very high GHG scenarios.
Table 4.4 provides a comparison of the temperature increases projected under the
various scenarios.
Table 4.4: Comparison of Temperature Increases by Representative Concentration
Pathway
Scenario 2046-2065 2081-2100
Mean Likely range Mean Likely range
Global Mean RCP 2.6 1.0 0.4 to 1.6 1.0 0.3 to 1.7
Surface RCP 4.5 1.4 0.9 to 2.0 1.8 1.1 to 2.6
Temperature RCP 6.0 1.3 0.8 to 1.8 2.2 1.4 to 3.1
Change (°C) RCP 8.5 2.0 1.4 to 2.6 3.7 2.6 to 4.8
The RCP 4.5 and RCP 6.0 scenarios are similar during the current IRP planning horizon.
Given 1) RCP 8.5 is at the high end of potential future GHG emissions, 2) there are
significant worldwide efforts to mitigate GHG emissions, and 3) the intermediate
scenarios are similar during the IRP planning horizon, Avista selected modeling results
based on RCP 4.5.
For each of the 19 BPA selected modeling combinations monthly river flows at each
Avista facility were converted to generation utilizing a regression model relating flow to
generation for each facility. The median of the 19 modeling combinations was selected to
represent generation at each facility for each specific month and year.
Avista also has contracts to receive a specified portion of generation from five facilities
on the Columbia River -Wells, Rock Island, Rocky Reach, Wanapum, and Priest Rapids
-these are owned and operated by Douglas PUD, Chelan PUD, and Grant PUD. BPA
analyzed generation at each of those facilities for each of the RCP 4.5 scenarios. As with
the Avista facilities, the median of the 19 modeling combinations was selected to
represent generation at each facility for each specific month and year over the planning
horizon.
Avista Corp 2023 Electric IRP 4-9
Chapter 4: Long-Term Position
Prior IRPs used monthly hydrogeneration by estimating hydrogeneration occurring under
current operating parameters for each water year from 1929 to 2008 (80-year hydro
record) and taking the median value for each month for each facility. In this analysis,
Avista changed the methodology to use the median monthly value of the previous 30
years, e.g. 2022 estimated generation is the median of generation values from 1992-
2021. Future years incorporate a mix of historical generation data and forecasted
generation data.
Table 4.5 and Figure 4.4 present the differences between the 80-year hydro record, the
recent 30-year record resulting from the RCP 4.5 analysis. Annual hydro generation is
similar between the 80-year hydro record and recent 30-year record, as it is projected
warming temperatures will increase annual hydro generation. On a monthly basis there
is an increase in hydro generation during the winter and early spring months and a
decrease in the summer months. This is consistent with regional forecasts predicting an
overall increase in annual precipitation with less snow fall and an earlier snow pact melt.
Table 4.5: 80-Year, Recent 30-Year, and RCP 4.5 Hydro Generation Forecast Comparison
80-Year Hydro Recent 30-Year RCP 4.5
(1929-2008) (1992-2021) (2019-2049)
Mean 598 595 645
Median 597 585 636
10th Percentile 424 437 447
90th Percentile 776 756 858
Standard Deviation 142 137 169
Figure 4.4: Comparison of Recent 80-Year, Recent 30-Year, and RCP 4.5 Generation
200
150 171 ~67
Difference between 80-Year Hydro and:
■ Recent 30 Year
100 ■ RCP 4.5 2019-2049
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Avista Corp 2023 Electric IRP 4-10
Chapter 4: Long-Term Position
In addition to impacting hydro generation, warming temperatures will also impact demand.
Specifically, there will be less heating required in the winter and more cooling required
during the summer. To assess the load impacts, the temperature data sets used as the
basis of the streamflow data sets were used in the load forecast and are described in
Chapter 2.
Heating degree days (HOOs) and cooling degree days (COOs) are inputs to the load
forecast model. A 20-year moving average of the HOOs and COOs is used. In the 2021
IRP the baseline forecast used the average of the most recent 20 years as a static input
for all forward forecast years. In this analysis, the median daily average temperature of
the RCP 4.5 model is used as the temperature data set compared to the 20-year moving
average for each forecast year. Figure 4.5 presents the net change in load resulting from
using the RCP 4.5 data in the forecast model compared to using the most recent 20-year
average held constant over all future years. The net change is presented for 2034 and
2045. The impact increases as warming temperatures are incorporated into the 20-year
moving average.
Figure 4.5: Impact of RCP 4.5 Temperature Data on Load Forecast
30
20
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Avista Corp 2023 Electric IRP 4-11
Chapter 4: Long-Term Position
Washington State Renewable Portfolio Standard
Washington's Energy Independence Act (EIA) promotes the development of regional
renewable energy by requiring utilities with more than 25,000 customers to source 15
percent of their energy from qualified renewables by 2020 . Utilities must also acquire all
cost-effective Energy Efficiency. In 2011, Avista signed a 30-year PPA with Palouse Wind
to meet the EIA goal. In 2012, an amendment to the EIA allowed Avista's Kettle Falls
biomass project to qualify toward the EIA goals beginning in 2016. More recently, Avista
acquired the Rattlesnake Flat wind project and Adams Nielson Solar4 projects and both
qualify for EIA and Clean Energy Transformation Act (CETA) compliance. The 30-year
wind PPA acquisition and planned upgrades to the Kettle Falls Generating Station project
in 2026 and Post Falls in 2029 will add additional qualified generation.
Table 4.6 shows the forecasted renewable energy credits (RECs)5 Avista needs to meet
the EIA's renewable requirement and the amount of qualifying resources within Avista's
current generation portfolio. This table does not reflect the additional flexibility available
for the REC banking provision in the EIA. Avista uses this banking flexibility as needed to
manage variation in renewable generation. After 2030, the renewable energy obligation
to meet the EIA is met, if Avista is compliant with the requirements of Washington State
CETA.
Table 4.6: Washington State EIA Compliance Position Prior to REC Banking (aMW)
2023 2025 2030
Two-Year RollinQ AveraQe WA Retail Sales Estimate 652.5 654.7 669.5
Renewable Goal 97.9 98.2 100.4
Incremental Hydro 17.4 17.4 17.4
Net Renewable Goal 80.5 83.5 83.0
Other Available RECs
Palouse Wind with Aoorentice Credits 46.0 46.0 46.0
Kettle Falls 36.1 36.1 46.8
Rattlesnake Flat with Apprentice Credits 60.6 60.6 60.6
Adams Neilson Solar --5.5
Boulder Community Solar 0.1 0.1 0.1
Rathdrum Solar 0.0002 0.0002 0.0002
30-year Wind PPA6 --41 .9
Net Renewable Position (before rollover RECs) 62.3 59.3 117.8
4 Adams Nielson can be used for the EIA after the voluntary Solar Select program ends in 2028.
5 These RECs are qualifying RECs within Avista's system. For state compliance purposes Avista may
transfer RECs between a state's allocation shares at market prices. Avista may also sell excess RECs to
reduce customer rates.
6 Online 1/1/2026, however, there is an option be on-line earlier.
Avista Corp 2023 Electric IRP 4-12
Chapter 4: Long-Term Position
Washington State Clean Energy Transformation Act
CETA requires Washington State electric utilities to serve 100 percent of Washington
retail load with renewable and non-emitting electric generation by 2045. Beginning in
2030, 80 percent of generation must be from renewable and non-emitting electric
generation and 20 percent can be met with alternative compliance options including
making alternative compliance payments, using unbundled RECs, or investing in energy
transformation projects. CETA requires the Washington Utilities & Transportation
Commission (WUTC) to adopt rules for implementation . The 20 percent alternative
compliance component is assumed to decrease in five percent steps to zero by 2045 in
this plan.
On June 29, 2022, the WUTC amended rules in Chapter 480-100 WAC to address some,
but not all, CETA requirements. The amended rules address CETA's prohibition of double
counting of nonpower attributes, electric purchases from centralized markets, and
treatment of energy storage, but do not address the interpretation of compliance with
RCW 19.405.030(1 )(a) defining "use".
While CETA rulemaking is incomplete, Avista through its Clean Energy Implementation
Plan (CEIP), has compliance targets approved by the WUTC for the period 2023-2025.
A vista's CEIP was approved with conditions in Docket UE-210628 by way of Order 01.
The CEIP does not include a commitment for the remaining interim 2026-2029 or 2030-
2044 periods. Between 2030 and 2044, all generation used to serve Washington electric
retail load must be greenhouse gas neutral. Twenty percent can be met through
alternative compliance options. Interim targets to meet the 2045 standard will be
determined in a future CEIP after final "use" rules have been adopted. Table 4.7 presents
the approved interim targets for 2022-2025 and preliminary targets through 2045.
Table 4.7: CETA Compliance Target Assumpions
Period Compliance Alternative
Target Compliance
2022 40.0% 0%
2023 47.5% 0%
2024 55.0% 0%
2025 62.5% 0%
2026 66.0% 0%
2027 69.5% 0%
2028 73.0% 0%
2029 76.5% 0%
2030 -2033 80.0% 20%
2034 -2037 85.0% 15%
2038 -2041 90.0% 10%
2041 -2044 95.0% 5%
2045 100.0% 0%
Note: A commitment has been made in the CEIP
for values in bold.
Avista Corp 2023 Electric IRP 4-13
Chapter 4: Long-Term Position
The following is a list of the assumptions included to develop the clean energy need
assessment in Figure 4.6.
• Qualifying clean energy is determined by procurement and delivery of energy to
Avista's system.
• The clean energy goal is applied to retail sales less in-state PURPA generation
constructed prior to 2019 plus voluntary customer programs such as Solar Select.
• Voluntary customer REC programs, such as Avista's My Clean Energy™ program,
do not qualify toward the CETA standard.
• Compliant compliance generation includes:
o Washington's share of hydro generation operating or contracted before
2022 (legacy hydro),
o All wind, solar, and biomass generation with Avista portfolio. Nonpower
attributes associated with Idaho's portion of generation according to the
established production transmission (PT) ratio will be purchased by
Washington at market rates if used for compliance,
o New acquired (post 2019) or contracted non-emitting generation including
hydro, wind, solar, or biomass can be used for compliance using the same
methodology as existing Avista-owned non-hydroelectric generation.
• Avista is not planning to use Idaho's share of legacy hydroelectric prior to 2030,
however actual compliance may include them due to variability in clean resource
availability (e.g., for a low water year). Avista includes these hydro resources
toward alternative compliance if it is economic to acquire the renewable energy
attributes.
• Avista uses total monthly generation to estimate whether clean energy counts
toward the compliance target or alternative compliance. If Washington's clean
energy total generation is greater than its "net retail load" excess generation counts
toward alternative compliance, but all generation totaling below "net retail load"
counts as compliant energy to meet the 4-year targets such as 80 percent by 2030.
A forecast based on a 30-year moving median of hydro conditions, average solar and
wind generation and the current load forecast is presented in Figure 4.6. The analysis
demonstrates Avista has enough qualifying resources to meet compliance targets through
2033 using this methodology.
2045 Planning
This IRP plans to a monthly energy target for CETA compliance, including 2045. Given
direction to plan for 100% clean energy in 2045, Avista seeks additional guidance on how
to plan for this future. For example, should utilities plan to be 100% clean energy in all
future conditions, thus requiring additional generation capacity and energy. How will
market transactions be treated (i.e. how will we know if clean energy is available on a
short hour or know how unspecified power will be treated) or should the utility plan on
being an energy island with high planning margins and energy risk adders? While there
are other issues likely develop, Avista requests guidance from the WUTC on these issues.
Avista Corp 2023 Electric IRP 4-14
Chapter 4: Long-Term Position
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Figure 4.6: Washington State CETA Compliance Position
--
ll) <D I'-co Cf) 0 ;:;:; N (") V ll) <D I'-co Cf) 0 ~ N (")
N N N N N (") (") (") (") (") (") (") (") (") V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N
c:::::=::i Compliance Target c::::::::J Maximum Alternative Target -Compliance Generation
-Compliance Shortfall -Alternative Compliance Generation Idaho Hydro
• • • • • • Net Retail Sales
Resource Adequacy Risk Assessment
Future planning of resource adequacy requires consideration of many risks. Avista is
utilizing the risks identified by the November 2020 paper Implications of Regional
Resource Adequacy Program on Utility Integrated Resource Planning7 as a framework to
present how Avista manages these risks. While Avista's current resource deficit is
projected for the mid-2030s, the risks outlined below will impact the ultimate resource
need.
Peak Demand Forecast
Avista uses a 1-in-2 peak load forecast, meaning half of the time the load will be above
and half the time load will be below the peak forecast. The forecast is based on historical
and forecasted future weather conditions. While weather is considered in the unknown
nature of future loads, there are also other load risks Avista considers in scenario analysis
specifically related to electrification. Avista developed several potential outcomes of
building and transportation electrification to understand potential impacts. The load
forecast scenarios are discussed in Chapter 2 and the resource strategies to solve higher
load is within Chapter 10.
7 Implications of a regional resource adequacy program on utility integrated resource planning
https://www.westernenergyboard.org/wp-content/uploads/11 -2020-LBN L-WI EB-regional-resource­
adequency-and-utility-integrated-resource-plan ning-final-paper. pdf.
Avista Corp 2023 Electric IRP 4-15
V ll) V V 0 0 N N
Chapter 4: Long-Term Position
Since the last IRP, Avista is participating in the currently non-binding development of the
Western Resource Adequacy Program (WRAP) with the intent of leveraging the diversity
of regional loads and generation across the WECC. This enables individual utilities to
reduce the need to carry the full burden of supplying for adequate capacity for their
systems. During this non-binding interim as Avista transitions to WRAP methodology, a
hybrid approach is being used for capacity planning. This approach incorporates the 2021
PRMs for summer and winter periods but uses the WRAP's Qualifying Capacity Credit
(QCCs) values assigned by the WRAP 's forward showing program .
Demand-Side Resource Contribution
Avista includes demand-side resources as options when determining the amount and
type of resources needed to meet future demand, but demand side resources may also
impact the net demand of the system prior to this inclusion-such as customer adoption.
Chapter 5 discusses each of the distributed energy resource (DER) option included in the
IRP, including energy efficiency, demand response, and distributed generation/energy
storage.
The focus of DER modeling within the IRP is to ensure supply side resources are not over
built. For example, roof top solar may reduce Avista's summer energy needs, but have
limited impact on winter loads. To address this risk , Avista includes an estimate of
incremental customer owned generation in its load forecast and includes scenario
analysis to understand impacts at higher levels. The greatest risk to uncertainty regarding
demand-side resources is whether they will impact winter peak load requirements and
given today, most additions are solar, this risk is low. If customers begin to install a winter
load impacting resources, Avista will need to reconsider the risk at that time.
Power Plant Retirement
Since the last IRP, Avista has announced that it will transfer ownership of its share of
Colstrip end of December 2025 . Avista also plans for plant retirements for each of its
existing natural gas peaking generators and has proposed end dates for its Combined
Cycle combustion turbines (CTs). This resource adequacy risk in this IRP is whether the
resources do not operate until the proposed end date. Avista does see this risk for two of
its plants; Northeast and Kettle Falls CT. Although Avista's capacity length compared to
its load can withstand the capacity loss of these two facilities from a reliability perspective.
Renewable Contribution
Increasing renewable penetration will impact the reliability of the power system if utilities
estimate their contributions too high . Avista found in the 2021 IRP it needed additional
resources to maintain the 5 percent LOLP when relying on renewable resources to meet
its peak loads. This IRP utilizes QCC values from the WRAP to identify the contributing
capacity for variable energy resources (VERs), although Avista identifies significant risk
associated with relying on VERs and uses a declining QCC value for these resources in
this IRP (see Chapter 6) to protect against over reliance on these resources for resource
adequacy. Avista also uses declining QCC values for energy storage resources as well.
Avista anticipates understanding QCC values in high renewable penetration scenarios
will be estimated by the WRAP in the future. Lastly, Avista did conduct a scenario analysis
Avista Corp 2023 Electric IRP 4-16
Chapter 4: Long-Term Position
to understand how the portfolio may change with higher levels of QCC values for these
same resources.
Storage Efficiency
Avista sees two risks for storage efficiency. The first risk is similar to the renewable QCC
contribution described above where short duration resources may help reliability in small
increments, but the reliability benefit is reduced as more storage is added to the system
due to the need to recharge the storage device after use. The second risk of energy
storage is the efficiency to recharge the device. Not all storage technologies have the
same recharging capability based on energy losses and time to recharge; therefore, each
of these considerations should be included in determining each device's credit toward
meeting peak demand.
Avista's resource strategy includes new energy storage technologies using renewable
fuels, such as green hydrogen and/or ammonia. These technologies protect against
declining efficiencies found in today's battery technology and offer longer durations
periods. But these resources have other risks including technology risk (these are new
and relatively unproven in large scale) and they require significant energy to produce the
fuel whereas the round trip efficiency is 20 to 25 percent.
Market Availability
In previous IRPs, Avista found market availability to be the greatest risk in resource
adequacy absent a resource adequacy market or program. Avista's previous resource
adequacy studies developed resource strategies to not exceed 330 MW of market
reliance . With development of the Western Power Pool's WRAP program and once
operational with binding requirements, Avista will likely increase its market reliance
threshold by adopting lower PRM values compared to those used today. Avista is
confident this market reliance is acceptable due to the fact by participating in the program
enforces all utilities to procure adequate capacity to ensure the greater system is reliable
to allow utilities to rely on each other when one may have higher loads.
Avista Corp 2023 Electric IRP 4-17
Chapter 4: Long-Term Position
This Page is Intentionally Left Blank
Avista Corp 2023 Electric IRP 4-18
Chapter 5: Distributed Energy Resources
5. Distributed Energy Resources
Prior IRPs included Distributed Energy Resources (DERs); however the documentation
had been placed across the energy efficiency, demand response, existing resources , and
new resource options chapters. With the heightened focus on DERs, these resources are
now presented in one chapter.
DER is defined in WAC 480-100-605 as:
Distributed energy resource means a non-emitting electric generation or
renewable resource or program that reduces electric demand, manages the level
or timing of electricity consumption, or provides storage, electric energy, capacity,
or ancillary services to an electric utility and that is located on the distribution
system, any subsystem of the distribution system, or behind the customer meter,
including conservation and energy efficiency.
Section Highlights
• Energy efficiency currently serves 155 aMW of load, representing nearly 11.4%
of customer demand.
• Over 2,600 energy efficiency measures and 16 demand response options are
considered for resource selection.
• Avista's net metering program includes 2,602 customers generating 18.8
megawatts.
• Community solar, roof-top solar, energy efficiency, demand response and
distributed energy storage are options for utility resource selection.
Energy Efficiency
Figure 5.1 illustrates Avista's historical electricity conservation acquisitions. Avista has
acquired 266 aMW of energy efficiency since 1978; however, the 18-year average
measure life means some measures are no longer reducing load as the measures have
either became code or standard practice. The 18-year measure life accounts for the
difference between the cumulative and online trajectories in Figure 5.1. Currently 155
aMW of energy efficiency serves customers, representing nearly 11.2 percent of 2022
customer load.
Avista's energy efficiency programs provide energy efficiency and education offerings to
the residential (inclusive of low-income and named communities), commercial, and
industrial customer segments. Program delivery mechanisms include prescriptive, site­
specific, regional, upstream, behavioral, home energy audit, market transformation and
third-party direct install options. Prescriptive programs provide fixed cash incentives
based on an average savings assumption for the measure across the region. Prescriptive
programs work best where uniform measures or offerings apply to large groups of similar
customers. Examples of prescriptive programs include the installation of qualifying high­
efficiency heating equipment or replacement of T8 florescent strip lighting with a high­
efficiency LED lamp.
Avista Corp 2023 Electric IRP 5-1
Chapter 5: Distributed Energy Resources
Site-specific programs, or customized offerings, provide cash incentives for cost-effective
energy saving measures or equipment that are analyzed and contracted but do not meet
prescriptive rebate requirements. Site-specific programs require customized approaches
for commercial and industrial customers because of the unique characteristics of each
premise and/or process. Other delivery methods build off these offerings with up-and
mid-stream retail buy-downs of low-cost measures, free-to-customer direct install
programs or coordination with regional market transformation efforts. In addition to
developing and delivering incentive offerings, Avista also provides technical assistance
in the forms of education, outreach, and other resources to customers to encourage
participation in efficiency programs and measures.
Figure 5.1 : Historical Conservation Acquisition (system)
30aMW 300 aMW
25aMW ·--· --·-·· 250 aMW
1/)
20aMW 200 aMW Cl C:
1/) ·s:
Cl "' C: en ·s: -Q) 15 aMW ----150 aMW "' > en +l
iii ~ ::I ::::I E C: 10 aMW 100 aMW C: ::I <t (.)
5aMW 50aMW
aMW aMW
The Conservation Potential Assessment
Avista retained Applied Energy Group (AEG) as an independent consultant to assist in
developing a Conservation Potential Assessment (CPA). The CPA is the basis for the
energy efficiency portion of this plan. The CPA identifies the 22-year potential for energy
efficiency and provides data on resources specific to Avista's service territory for use in
the resource selection process and in accordance with the Energy Independence Act's
(EIA) energy efficiency goals. The potential assessment considers the impacts of existing
programs, the influence of known building codes and standards, technology
developments and innovations, legislative policy changes to the long-term economic
influences and energy prices. The CPA report is included in Appendix C along with a list
of energy efficiency measures is in Appendix F.
AEG first developed estimates of technical potential, reflecting the adoption of all
conservation measures, regardless of cost-effectiveness or customers' likeliness to
participate. The next step identified the achievable technical potential; this measure
modifies the technical potential by accounting for customer adoption constraints by using
Avista Corp 2023 Electric IRP 5-2
Chapter 5: Distributed Energy Resources
the Power Council's 2021 Plan ramp rates. The estimated achievable technical potential,
along with associated costs, feed into the PRiSM model to select cost-effective measures.
AEG took the following steps shown in Figure 5.2 to assess and analyze energy efficiency
and potential within Avista's service territory.
Figure 5.2: Analysis Approach Overview ,,.~,... ~,....
~~ ~~
•Market
Characteril.Btion
• Avista customer
accounts
• NEEA Surveys
• Avista GenPOP
Survey
• Energy Market
profiles
• Secondary
sources
• Project the
baseline
•PNW andAEO
equipment growth
and purchases
• Avista load
forecasts
•Codes and
standards
• Secondary data
• Theoretical
Maximum
•NWPCC 2021
Pow er Plan and
RTF USE
Workbook
Assumptions
• Secondary
Sources (DEE"1)
•Avista
Accomplishments
•Establish
Customer
Acceptance
•NWPCC 2021
Power Plan ramp
rates
• Avista program
results
• Synthesize
• IRP Inputs from
PRiSI,!
• Measure
Summary
AEG's conservation potential assessment included the following steps:
1. Perform a market characterization to describe sector-level electricity use for the
residential (inclusive of low income), commercial and industrial sectors for the 2022
base year.
2. Develop a baseline projection of energy consumption and peak demand by sector,
by segment and by end use for 2023 through 2045.
3. Define and characterize several hundred conservation measures to be applied to
all sectors, segments and end uses.
4. Estimate Technical Potential and Achievable Technical Potential at the measure
level in terms of energy and peak demand impacts from conservation measures
for 2023-2045.
Market Segmentation
The CPA considers Avista customers by state and by sector. The residential sector
includes single-family, multi-family, manufactured homes, and low-income customers1
using Avista's customer data and U.S. Census data from the American Community
Survey (ACS). For the residential sector, AEG utilized Avista's customer data and prior
CPA ratios developed from census information. AEG incorporated information from the
Northwest Energy Efficiency Alliance's (NEEA) Commercial Building Stock Assessment
to assess the commercial sector by building type, installed equipment and energy
consumption. Avista analyzed the industrial sector for each state because of their unique
energy needs. AEG characterized energy use by end use within each segment in each
sector, including space heating, cooling, lighting, water heating, or motors; and by
technology, including heat pumps and resistance-electric space heating.
1 The low-income threshold for this study is 200 percent of the federal poverty level. Low-income information
is available from U.S. census data and the American Community Survey data for Washington customers
only.
Avista Corp 2023 Electric IRP 5-3
Chapter 5: Distributed Energy Resources
The baseline projection is a "business as usual" metric without future utility conservation
or energy efficiency programs. It estimates annual electricity consumption and peak
demand by customer segment and end use absent future efficiency programs. The
baseline projection includes the impacts of known building codes and energy efficiency
standards as of 2021 when the study began. Codes and standards have direct bearing
on the amount of energy efficiency potential due to the reduction in remaining end uses
with potential for efficiency savings. The baseline projection accounts for market changes
including:
• customer and market growth ;
• income growth;
• retail rates forecasts;
• trends in end use and technology saturation levels;
• equipment purchase decisions;
• consumer price elasticity;
• income; and
• persons per household.
For each customer class, AEG compiled a list of electrical energy efficiency measures
and equipment, drawing from the NPCC's (Council) 2021 Power Plan, the Regional
Technical Forum, and other measures applicable to Avista. The 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 over
2,600 measures and performs an economic screening on each measure for every year
of the study to develop the economic potential for Avista's service territory and individually
by state. Avista supplements energy efficiency activities by including potentials for
distribution efficiency measures consistent with EIA's conservation targets and the NPCC
2021 Power Plan.
Overview of Energy Efficiency Potential
AEG's approach adhered to the conventions outlined in the National Action Plan for
Energy Efficiency Guide for Conducting Potential Studies. 2 The guide represents
comprehensive national industry standard practice for specifying energy efficiency
potential. Specifically, two types of potential were included in this study, as discussed
below. Table 5.1 shows the CPA results for Technical and Achievable Technical Potential
by state.
2 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for
2025: Developing a Framework for Change. www.epa.gov/eeactionplan.
Avista Corp 2023 Electric IRP 5-4
Chapter 5: Distributed Energy Resources
Table 5.1: Cumulative Potential Savings (Across All Sectors for Selected Years)
2024 2025 2030 2040 2042
Technical Potential (GWh) 308.7 480.8 1,365.6 2,439.6 2,536.9
Washinqton (GWh) 209.3 325.4 923.3 1,645.7 1,707.1
Idaho (GWh) 99.4 155.4 442.2 793.9 829.8
Total Technical Potential (aMW) 35.2 54.9 155.9 278.5 289.6
Technical Achievable Potential (GWh) 176.0 281.5 910.8 1,828.4 1,919.2
Washinqton (GWh) 117.9 188.8 613.3 1,234.0 1,292.6
Idaho (GWh) 58.1 92.7 297.6 594.4 626.6
Total Technical Achievable Savinqs (aMW) 20.1 32.1 104.0 208.7 219.1
Future programs must be cost effective to be selected for future implementation. Figure
5.3 illustrates the supply curve of this potential using their associated price per MWh. For
Idaho savings, the potential has a near zero cost using the Utility Cost Test (UCT) method
until approximately 100 GWh, then quickly rises . As for Washington, using the Total
Resource Cost (TRC) method, there is "no cost" energy efficiency until reaching
approximately 250 GWh , then linearly increases until around 900 GWh, then goes up
exponentially. The amount of energy efficiency selected will be where the supply curve
meets the avoided cost. For example, if Washington's avoided cost were $100 per MWh,
then 500 GWh of energy efficiency would be selected. Avista uses a more sophisticated
approach than this for resource selection where it looks at each program's individual cost
and benefits compared to alternatives, but the supply curve demonstration is a simplified
cost and benefit illustration of the available energy efficiency.
Figure 5.3: Jurisdiction Supply Curve
$300 I
$250 ... "' 0 $200 u
Q) -N ...C: ==~ $150 ~==
J .,
Q) I..
...J Q)
$100 It) C.
"q'fh ·-
• Washington_ TRC
• ldaho_UCT
'-=:t N $50 0 N
$0
-$50
0 200 400 600 800 1 , 000 1,200
2024-45 Cumulative GWh
Avista Corp 2023 Electric IRP 5-5
Chapter 5: Distributed Energy Resources
Technical Potential
Technical Potential is the theoretical upper limit of energy efficiency potential. It
assumes customers adopt all feasible measures regardless of cost. At the time of
existing equipment failure, it assumes customers replace failed equipment with the
most efficient option available.
In new construction, customers and developers choose the most efficient equipment
option relative to applicable codes and standards. Non-equipment measures could be
installed apart from equipment replacements. They are implemented according to
ramp rates developed by the Council for its 2021 Power Plan and apply to 100 percent
of the applicable market. The Technical Potential case is a theoretical construct and
is provided for planning and informational purposes.
Technical Achievable Potential
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 affecting market penetration of energy efficiency
measures. AEG used ramp rates from the Council's 2021 Power Plan in development
of the Technical Achievable Potential.
For the Technical Ach ievable Potential case, a maximum achievability multiplier of 85
to 100 percent is applied to the ramp rate per Council methodology. This factor
represents a reasonable achievable potential to be acquired through available
mechanisms, regardless of how energy efficiency is achieved. Thus, the market
applicability assumptions utilized in this study include savings outside of utility
programs . Avista uses Technical Achievable Potential as an input to its resource
selection.
Integrating Results into Business Planning and Operations
The CPA and IRP energy efficiency evaluation processes provide high-level estimates of
cost-effective acquisition opportunities. Results establish baseline goals for continued
development and enhancement of energy efficiency programs, but do not provide enough
detail to form an actionable acquisition plan. Avista uses results from both processes to
establish a budget for energy efficiency measures, determine the size and skillsets
necessary for future operations and identify general target markets for energy efficiency
programs. This section discusses recent operations of the individual sectors and energy
efficiency business planning.
The CPA is used for implementing energy efficiency programs to:
• Identify conservation resource potentials by sector, segment, end use and
measure. Energy efficiency staff uses CPA results to determine the segments and
end uses/measures to target.
• Identify measures with the highest benefit-cost ratios to help the utility acquire the
highest benefits for the lowest cost. Ratios evaluated include TRC in Washington
and UCT in Idaho.
Avista Corp 2023 Electric I RP 5-6
Chapter 5: Distributed Energy Resources
• Identify and target measures with large potential but significant adoption barriers
that the utility may be well-positioned to address through innovative program
design or market transformation efforts.
• Optimize the efficiency program portfolio by analyzing cost effectiveness, potential
of current measures and programs; and by determining potential new programs,
program changes and program sunsets.
The CPA illustrates potential markets and provides a list of cost-effective measures to
analyze through the ongoing energy efficiency business planning process. This review of
both residential and non-residential program concepts and sensitivity provides more
detailed assumptions feeding into program planning.
Residential Sector Overview
Avista's residential portfolio of efficiency programs engages and encourages customers
to consider energy efficiency improvements for their home. Prescriptive rebate programs
are the main component of this portfolio, augmented with other interventions. Other
interventions include select distribution of low-cost lighting and weatherization materials,
direct-install programs as well as multi-faceted, multichannel outreach and customer
engagement.
Residential customers received over $1.4 million in rebates in 2021 to offset the cost of
implementing energy efficiency measures. All programs within the residential portfolio
contributed over 2,982 MWh to the 2021 annual first-year energy savings.
Low-Income Sector Overview
Currently Avista leverages the infrastructure of several network Community Action
Agencies (CAA) and one tribal weatherization organization to deliver energy efficiency
programs for the low-income residential customers in Avista's service territory. CAAs
have resources to income qualify, prioritize, and treat clients' homes based upon several
characteristics beyond Avista's ability to reach. These agencies also have other
resources to leverage for home weatherization and other energy efficiency measures
beyond Avista's contributions. The agencies have both in-house and/or contract crews
available to install many of the efficiency program measures.
Avista's general outreach for this sector is a "high touch" customer experience for
vulnerable customer groups including seniors and those with limited incomes. Each
outreach encounter includes information about bill payment options and energy
management tips, along with the distribution of low-cost weatherization materials. Many
events are coordinated each year, including Avista-sponsored energy fairs, and the
energy resource van. Avista also partners with community organizations to reach these
customers through other means such as area food banks/pantry distribution sites, senior
activity centers, or affordable housing developments. Low-income energy efficiency
programs contributed 460 MWh of annual first-year electricity savings in 2021 .
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
Avista Corp 2023 Electric IRP 5-7
Chapter 5: Distributed Energy Resources
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 non-homogenous.
More than 2,802 prescriptive and site-specific nonresidential projects received funding in
2021 . Avista contributed over $10.7 million for energy efficiency upgrades to offset costs
in nonresidential applications. Non-residential programs realized over 40,686 MWh in
annual first-year energy savings in 2021.
Demand Response Potential Study
Historically, demand response (DR) programs provide capacity at times when wholesale
prices are unusually high, when generation , transmission or natural gas shortages occur,
or during an emergency grid-operation situation. Traditional DR programs such as time­
of-use rates, peak time rebates, direct load control (DLC) programs, and bi-lateral
agreements incentivize load reductions to specific enrolled customers during such
periods until the load event is over or the customer meets their commitment. More
recently, DR driven initiatives are also providing reliable ancillary service support in
wholesale markets.
Avista's current DR resources include commercial EV Time-of-Use {TOU) rates and one
bilateral agreement with an industrial customer for 30 MW. This contract was executed in
2022 for a four-year term with provisions to extend another six-years. Additional DR
resources are planned as pilots in Washington State to begin in 2024 and include a TOU
program, a Peak Time Rebate (PTR) program and a DLC program for grid-enabled water
heaters. These pilots will influence future IRPs, just as past pilot experience influenced
this IRP.
Historical Demand Response Programs and Pilots
Avista's experience with DR dates back at least to the 2001 Western Energy Crisis. Avista
responded with all-customer and irrigation customer buy-back programs and bi-lateral
agreements with its largest industrial customers. These programs, along with enhanced
commercial and residential energy efficiency programs, reduced the need for purchases
in very high-cost wholesale electricity markets. A July 2006 multi-day heat wave prompted
Avista to request DR voluntarily through media outlets by asking customers to voluntarily
conserve energy and entered into short-term agreements with large industrial customers
to curtail loads due to the extreme regional and local temperatures not seen in the
Spokane Area since 1961 .
Between 2007 and 2009, Avista piloted technologies to examine DR cost-effectiveness
and customer acceptance. The pilot tested scalable DLC devices based on installations
in approximately 100 volunteer households in Sandpoint and Moscow, Idaho. The sample
allowed Avista to test DR with the benefits of a larger-scale project, but in a controlled ,
measurable, and customer-friendly manner. Avista installed DLC devices on residential
heat pumps, water heaters, electric forced-air furnaces, and air conditioners to control
operations 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
Avista Corp 2023 Electric IRP 5-8
Chapter 5: Distributed Energy Resources
study as part of the pilot. The program provided Avista and customers experience with
"near-real time" energy-usage feedback equipment. Information gained from the pilot is
summarized in a report filed with the Idaho Public Utilities Commission. 3
Following the North Idaho DR pilot program, Avista was part of the 2009 to 2014
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 included forced-air electric furnaces, heat
pumps and central air-conditioning units. The non-traditional DLC approach was used,
meaning the DR events were not prescheduled , but rather Avista controlled customer
load through an automated process based on utility or regional grid needs while using
predefined customer preferences.4 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 customers' smart thermostat. Avista reported
information gained from this project to the prime sponsor for use in the SGDP's final
project report and compilation with other SGDP initiatives. 5
Experiences from both pilots showed high customer engagement; however, recruiting
participants was challenging. Avista's service territory has a high level of natural gas
penetration meaning many customers cannot participate in typical DLC electric space and
water heat programs with their natural gas appliances. Additionally, customers did not
seem overly interested in the DLC programs as offered. BPA found similar customer
interest challenges in their regional DLC programs.6 A 2019 Avista survey, conducted by
the Shelton Group, also found low customer interest to participate in DR programs.
Avista paid customers direct incentives for program participation in both DLC pilots.
Incentive levels were a premium to recruit and retain customers and were not intended to
be scalable. Avista will need 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 Progress Report.
Demand Response Potential Assessment Study
Avista retained AEG to study the DR potential for Avista's Washington and Idaho service
territory for this IRP. The study estimates the magnitude, timing, and costs of DR
resources likely available to Avista for meeting both winter and summer peak loads.
Figure 5.4 outlines AEG's approach to determine potential DR programs in Avista's
service territory. Many DR programs require Advanced Metering Infrastructure (AMI) for
settlement purposes. All DR pricing programs, behavioral and third-party contract
3 https://puc.idaho.gov/fileroom/cases/elec/AVU/AVUE0704/company/20100303FINAL %20REPORT.pdf
4 For example, no more than a two-degree Fahrenheit offset for residential customers and an energy
management system at WSU with a console operator.
5 https://www.smartgrid.gov/files/OE0000190 _ Battelle_Fina1Rep _2015 _ 06. pdf.
6 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.
Avista Corp 2023 Electric IRP 5-9
Chapter 5: Distributed Energy Resources
programs included in this study require AMI as an enabling technology. AMI deployment
is complete in Washington , and AEG broadly assumed that Avista would follow with AMI
metering in Idaho beginning in 2024 and a three-year ramp rate for full deployment,
finishing in 2027.
AEG used the same market characterization for this potential assessment study as used
in the CPA. This became the basis for customer segmentation to determine the number
of eligible customers in each market segment for potential DR program participation and
provided consideration for DR program interactions with energy efficiency programs. The
study compared Avista's market segments to national DR programs to identify relevant
DR programs for analysis.
AMI
Infrastructure
Analysis
• AMI is required for
participation in
certain programs
• Determines eligible
populations for rate
based options
• Analysis assumes all
large C&I customers
in the state have
Interval Demand
Recorder (IDR)
meters
Figure 5.4: Program Characterization Process
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 parameter
• In the context of high
and low potential
cases
Develop
Program
Hierarchy
• Ensure the potential
is not double
counted between
programs
This process identified several DR program options shown in Table 5.2. The different
types of DR programs include two broad classifications: curtailable/controllable DR and
rate design programs. Except for the behavioral program, curtailable/controllable DR
programs represent firm, dispatchable and reliable resources to meet peak-period loads.
This category includes DLC, Firm Curtailment (FC), thermal and battery storage and
ancillary services. Rate design options offer non-firm load reductions that might not be
available when needed but still create a reliable pattern of potential load reduction . Pricing
options include time-of-use, peak-time rebate, and variable peak pricing. Each option
requires a new rate tariff for each state in Avista's service territory.
Avista Corp 2023 Electric IRP 5-10
Chapter 5: Distributed Energy Resources
Table 5.2: Demand Response Program Options by Market Segment
Program
Type
DR Program
Program
Option
Curtailable/
Controllable
DLC Central AC
DLC Smart
Thermostat -Coolin
Rates
DLC Smart
Thermostat -Heatin
DLC CT A-2045
Water Heatin
DLC Water Heating
DLC Vehicle
Char in
DLC Smart
A liances
Third Party Contracts
Thermal Energy
Stora e
Battery Energy
Stora e
Behavioral
Ancillary Services
Time-of-Use Opt-in
Variable Peak Pricing
Rates
Peak-Time Rebate
Electric Vehicle
Time-of-Use
Participating Market Segment
Res. Sm. Large. Extra
Com. Com.I Large
Ind. Com./
Ind.
X X
X X
X X
X X
X
X X
X X
X X X
X X X X
X
X X X X
X X X X
X X X X
X X
X X
Demand Response Program Descriptions
Direct Load Control
Season Impacted
Winter Summer
X
X
X X
X X
X X
X X
X X
X
X X
X X
X X
X X
X X
X X
X X
DLC programs for Avista's Residential and General Service customers in Idaho and
Washington would aim to allow Avista to directly control a variety of customer end-use
appliances during peak times throughout the year. DLC Smart Thermostat programs
would leverage a customer's smart thermostat installation relying on the customer's
WiFi for communications. Likewise, DLC Smart Appliances assume customer
resources as the enabling technology. DLC Central AC, DLC Water Heating, and DLC
CTA-2045 Water Heating programs assume the enabling technology is a utility
provided version of a load control switch. Smart appliances included in this analysis
include refrigerators, clothes washers and dryers. Typically, DLC programs take five
years to ramp up to maximum participation levels.
Avista Corp 2023 Electric I RP 5-11
Chapter 5: Distributed Energy Resources
Third Party Contracts -Firm Curtailment
Customers participating in a firm curtailment program agree to reduce demand by a
specific amount or to a pre-specified consumption level during the event in exchange
for fixed incentive payments. Customers receive payments while participating in the
program even if they never receive a load curtailment request while enrolled in the
program. The capacity payment typically varies with the firm reliability-commitment
level. In addition to fixed capacity payments, participants receive compensation for
reduced energy consumption. Because the program includes a contractual agreement
for a specific level of load reduction, enrolled loads have the potential to replace a firm
generation resource.
Customers with maximum demand greater than 200 kW and operational flexibility are
attractive candidates for firm curtailment programs. Examples of customer segments
with high participation possibilities include large retail establishments, grocery chains ,
large offices, refrigerated warehouses, water-and wastewater-treatment plants and
industries with process storage (e.g., pulp and paper, cement manufacturing).
Customers with operations requiring continuous processes, or with relatively inflexible
obligations, such as schools and hospitals, generally are not good candidates for
curtailment programs. The study factors in these assumptions to determine the eligible
population for participation in this program and assumes a third party would administer
all aspects of the program.
Thermal Energy Storage
This emerging technology has been primarily used in non-residential buildings and
applications but may have the potential to be used in the future for residential applications
as the technology advances. Thermal energy storage technologies draw electricity during
low demand periods and store it as ice sealed inside the unit. A variable speed fan can
automatically circulate the cool air throughout a room using the stored energy (ice) rather
than having to draw energy from the grid during peak times to chill the air.
Battery Energy Storage
Battery energy storage technologies draw electricity during low demand periods and store
it for use later during peak times . This study assumes energy is stored using
electrochemical processes as found with lithium-ion battery equipment.
Behavioral
A behavioral program is a voluntary reduction in response to digital behavioral
messaging. These programs typically occur in conjunction with energy efficiency
behavioral reporting programs and communicate the request to customers to reduce
usage via text or email messages. AMI technology is needed to evaluate and measure
the impact of the program for events.
Time of Use Rates (Opt-In)
A TOU rate is a time-varying rate. Relative to a revenue-equivalent flat rate, the rate
during higher load or cost periods are higher, while the rate during other periods is lower.
This provides customers with an incentive to shed or shift consumption out of the higher­
price on-peak hours to the lower cost off-peak hours. TOU is not a demand-response
Avista Corp 2023 Electric IRP 5-12
Chapter 5: Distributed Energy Resources
option, per se, but rather a permanent load shedding or shifting opportunity. Large price
differentials are generally more effective than smaller differentials for TOU programs.
The DR study considered two types of TOU pricing options. In an opt-in rate, participants
voluntarily enroll in the rate. An opt-out rate places all customers on the time-varying rate,
but they may opt-out and select another rate later. Avista only used TOU Opt-in for this
analysis.
Variable Peak Pricing
The Variable Peak Pricing (VPP) amount changes daily to reflect system conditions and
costs for peak hours. Under a VPP program, on-peak prices for each weekday are made
available the previous day. Variable peak pricing bills customers for their actual
consumption during the billing cycle at these prices. Over time, establishment of event­
trigger criteria enables customers to anticipate events based on extreme weather or other
factors. System contingencies and emergency needs are good candidates for variable
peak pricing events. VPP program participants are required to be enrolled in a TOU rate
option.
Peak Time Rebate
Participation in a Peak-Time-Rebate (PTR) program is voluntary. In an event, participants
are notified a day in advance for a two-to six-hour event time during peak hours. If
customers do not participate, there is no penalty. If they do participate, they receive a bill
credit based on the amount of energy reduced as compared to a calculated baseline.
PTR is not dependent on enrollment in other DR programs, but like the other pricing
programs, it does require AMI for settlement purposes.
Electric Vehicle Time of Use
The study applied the most recent electric-vehicle load forecast to Avista's current rate
schedules 13 and 23 in Washington. Rather than a typical TOU rate that applies on-off
peak prices to whole building usage, the EV TOU rate program applies on-off peak prices
exclusively to EV loads that are metered separately. When AMI is available in Idaho, a
similar pricing program is assumed in the study.
Planned Pilot Programs
AEG assessed a set of pilot programs based on Avista's planned DR program roll-out
beginning in 2024 and includes TOU rate options, PTR, and DLC of grid-enabled water
heaters. Broad assumptions were made for all three pilot programs since all are still under
development. AEG forecasted the potential for these programs to 2045 as if the programs
ramped up to fully-fledged programs after the pilots. Each pilot will run for three years;
the TOU Opt-in will have an optional two-year extension depending on results. 7 Each
program will be offered to residential and general service customers only.
7 Potential results for the TOU Opt-in Pilot do not include the two-year extension and are based on a three­
year pilot.
Avista Corp 2023 Electric I RP 5-13
Chapter 5: Distributed Energy Resources
Demand Response Program Participation
AEG's forecast for DR potential uses a database of existing program information and
insights from market research results representing "best-practice" estimates for
program participation. The industry commonly follows this approach for arriving at
achievable potential estimates. However, practical implementation experience
suggests there is uncertainties in factors such as market conditions, regulatory
climate, the economic environment, and customer sentiments will influence customer
participation in DR programs.
Once initiated, DR options require time to ramp up to a steady state because of the
time needed for customer education, outreach, and recruitment; in addition to the
physical implementation and installation of any hardware, software, telemetry, or other
enabling equipment. DR programs included in the AEG study have ramp rates
generally with a three-to five-year timeframe before reaching the steady state.
Table 5.3 shows the steady-state participation rate assumptions for each DR program
option. Space cooling is split between DLC Central AC and Smart Thermostat options.
Likewise, eligible EV charging, general service customers are split between the TOU
(opt-in or opt-out) programs and the EV TOU program . Eligible customers for each
customer class are calculated based on market characterization and equipment end
use saturation. 8
Table 5.3: DR Program Steady-State Participation Rates (Percent of Eligible Customers)
DR Program Residential General Large Extra
Service Service/ General Large
Small Service General
Commercial Service
Direct Load Control (DLC) of central AC 10% 10% --
DLC of domestic hot water heaters (DHW) 15% 5% --
Smart Thermostats DLC Heating 5% 3% --
CT A-2045 hot water heaters 50% 50% --
Smart Thermostats DLC Coolinq 20% 20% --
Smart Aooliances DLC 5% 5% --
Third Party Contracts -15% 22% 21%
DLC Electric Vehicle Charging 15% ---
Time-of-Use Pricing Opt-in 13% 13% 13% 13%
Time-of-Use Pricing Opt-out 74% 74% 74% 74%
Variable Peak Pricinq --25% 25%
Peak-Time Rebate 15% 15% --
Electric Vehicle Time-of-Use -51% 51% -
Thermal Enerav Storage -0.5% 1.5% 1.5%
Battery Energy Storage 0.5% 0.5% 0.5% 0.5%
Behavioral 20% ---
8 See the Demand Response Potential Appendix found within the 2022-2045 Avista Electric CPA found in
Appendix C.
Avista Corp 2023 Electric IRP 5-14
Chapter 5: Distributed Energy Resources
Cost and Potential Assumptions
Each DR program used in this evaluation is assigned an average load reduction per
participant per event, an estimated duration of each event, and a total number of event
hours per year. Costs are also assigned to each DR program for annual marketing,
recruitment, incentives, program development, and administrative support. These
assumptions result in potential demand savings and total cost estimates for each
program independently and on a standalone basis.
If Avista offers more than one program, then the potential for double counting exists.
To address this possibility, a participation hierarchy was assumed and defines the
order customers take the programs for an integrated approach. These savings and
costs results were then used in Avista's modeling . See Appendix C for additional detail
on DR resource assumptions used in developing potential savings and cost results.
The estimated savings for reach program and its levelized costs is shown in Table 5.4.
The cost of the programs within this table represents the on-going operations and capital
cost required to start and maintain these programs. The capital costs are amortized and
recovered over a 10-year period. These tables include the estimated potential megawatt
savings for 2030 and 2045 for illustrative purposes of program potential. These estimates
are the expected amount of demand reduction from all program participants using a
"stand-alone" methodology, whereas potential may decline for a program in multiple
programs are put in place. It is also worth noting, Avista will require a higher amount of
contracted load to achieve these savings, these amounts are the expected net savings
from all participants.
Table 5.4: System Program Cost and Potential
$/kW-Winter (MW) Summer(MW)
Program Month 2030 2045 2030 2045
Battery Enerav Storage 47.1 1.3 5.5 1.3 5.5
Behavioral 13.3 3.2 4.2 3.4 4.4
DLC Central AC 13.9 --10.9 15.4
DLC Electric Vehicle CharQinQ 90.9 2.3 29.3 2.3 29.3
DLC Smart Aooliances 27.3 3.2 3.7 3.2 3.7
DLC Smart Thermostats-Cooling 14.7 --21 .9 30.7
DLC Smart Thermostats-Heating 2.5 4.9 5.8 --
DLC Water Heatina 52.7 2.1 2.4 2.1 2.4
CT A-2045 ERWH 34.8 1.8 5.7 1.7 5.3
CTA-2045 HPWH 61.4 0.5 2.6 0.2 1.0
Thermal Enerav Storage 60.7 --0.7 0.8
Third Party Contracts 8.4 24.8 29.6 24.4 29.1
Time-of-Use Oot-in 4.9 7.8 9.9 8.1 10.3
Electric Vehicle TOU Opt-in 23.5 0.3 4.7 0.3 4.7
Variable Peak PricinQ Rates 2.6 4.7 5.5 4.6 5.4
Peak Time Rebate 3.4 11.2 14.8 11 .8 15.5
Total Potential 68.3 123.6 97.1 163.6
Avista Corp 2023 Electric IRP 5-15
Chapter 5: Distributed Energy Resources
There are a few other factors including the evaluation of DR the PRiSM model considers,
the first is energy value of the program. Some program opportunities reduce energy
usage permanently, but most programs have snap back load where additional energy
returns later. Avista determined the net value of these load changes using hourly
wholesale market prices discussed in Chapter 8 compared to a time series of how the
load profile would result if the program was dispatched.
The second major factor related to whether a program is cost effective compared to other
alternatives is the resources' ability to qualify as load reduction or the programs Qualifying
Capacity Credit (QCC). At this time, the QCC is uncertain for these types of programs in
the future Western Resource Adequacy Market (WRAP), but this analysis assumes a 6-
hour reduction is required to receive 100 percent QCC, whereas the QCC is a percentage
of the hour reduction. For example, a 4-hour program is 67 percent and a 3-hour program
is 50 percent. These values assume today's system and will reduce as the regional
electric system's load is met with more variable energy resources and storage. Currently,
the WRAP has not completed a study of the long-term QCC of DR or any other resources,
therefore Avista's assumption hinges on regional studies of reduced effective load
carrying capability (ELCC) studies in the public domain, such as the March 2019 E3 Study
on Resource Adequacy in the Pacific Northwest to make this estimate, the resulting QCC
value is shown for a 4-hour program in Figure 5.5.
Figure 5.5: Demand Response QCC Forecast for 4-hour Program
80%
70% 7% -63%
"'O 60% 57% Q) ... u 48% >, 50% ~ 0 ~ 40% C. 36%
~ 30%
U 30% 27% en 23% C:
lll'ili1'i·11 ~ 20%
~
::I 10% 0
0%
(") '<t LO co I'--co 0) 0 ...... N (") '<t LO co I'--co 0) 0 ...... N (") '<t LO N N N N N N N (") (") (") (") (") (") (") (") (") (") '<t '<t '<t '<t '<t '<t 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N
Avista Corp 2023 Electric IRP 5-16
Distributed Generation Resources
Customer-Owned Generation
Chapter 5: Distributed Energy Resources
Avista has 2,602 customer-installed net-metered generation projects on its system as of
November 2022, representing a total installed capacity of 18.8 MW. Eighty-nine percent
of installations are in Washington; most are in Spokane County. Figure 5.6 shows annual
net metering customer additions since 20029 and forecasted installations from Avista's
load forecast. Solar is the primary net metered technology followed by wind, combined
solar and wind systems, and biogas. The average size of the customer installations is 7.2
kilowatts. In Idaho, solar installation rates continue to increase each year without a major
subsidy, but total only 280 customers compared to Washington's 2,322 customer
installations. In addition, in recent years, net-metered installations are exponentially
increasing due to federal incentives, increasing solar vendor sales, environmental
concerns, rising energy costs, and expiring state incentives. In addition, 2021 and 2022
is seeing a "catch-up" on the installation back-log that occurred during the COVID-19
pandemic. If net-metering customers continue to increase, Avista may need to adjust rate
structures for these customers. Much of the cost of utility infrastructure to support reliable
energy delivery is recovered in energy rates. Net metering customers continue to benefit
from this infrastructure but are no longer purchasing as much energy, thereby transferring
some of their grid infrastructure costs to customers not generating their own power.
Figure 5.6: Avista's Net Metering Customers
1,600 140 Actual Forecast §'
1,400 120 ~
II) ~ ,_
1,200 -Idaho Q)
E 100 (.)
-Washington ra
0 a. -1,000 -Cumulative MW ra II) (.) :::, • 80 (.) -"C
~ 800 • ~ .s!
Q)
__ ,
60 ra z • -• -. II)
ra 600 C: • :::, ; ---
Q)
C:
--
40 > C: 400 :
-E <( . •••• ra • :::,
200 I • 20 E :::, --·· (.)
0 0
N '<I' (0 co 0 N '<I' (0 co 0 N '<I' (0 co 0 N '<I' (0 co 0 N '<I' 0 0 0 0 ~ ~ 0 ~ ~ N N N N N (") (") (") (") (") '<I' '<I' '<I' 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Avista-Owned Solar
Avista operates three small solar DER projects. The first solar project is three kilowatts
located at its corporate headquarters. Avista installed a 15-kilowatt solar system in
Rathdrum, Idaho to supply its My Clean Energy™ (formerly Buck-A-Block) voluntary
9 The 2022 results are through September.
Avista Corp 2023 Electric IRP 5-17
Chapter 5: Distributed Energy Resources
green energy program. The 423-kW Avista Community Solar project, located at the
Boulder Park property, began service in 2015.
Table 5.5: Avista-Owned Solar Resource Capability
okane, WA 3
Rathdrum Solar Rathdrum, ID 15
Boulder Park Solar S okane Valle , WA 423
Total 441
Generation & Storage Opportunities
Past IRP analysis included utility owned distribution sized generation and storage, but
this analysis also includes residential, commercial, and community sized projects.
Customer or distribution sized resources have gained traction as avenues to promote
equitable outcomes to specific communities or solve local supply issues. For this analysis
these DE Rs are included as resource options for the Named Community Investment Fund
(NCIF) but can be selected otherwise if cost effective. The resource configurations and
costs are shown in Table 5.6. The costs are shown in nominal levelized cost dollars and
include the benefits of the Inflation Reduction Act through 2033, the cost assumptions are
based on information provided by TAC members and the 2022 NREL resource cost
study.10 The Low-Income Community Solar option included is based on the expected net
cost to Avista customers after accounting for grants given by the State of Washington.
The costs are levelized cost of energy for solar resources over the life of the asset and
for energy storage is the levelized cost of capacity for the life of the asset assuming
battery reconditioning .
Table 5.6: DER Generation & Storage Options Size and Cost
Project Name
Existin res. buildin solar
Exist olar with stora e
New
Com. buildin solar with stora e
Utilit owned solar arra
Utilit owned sol e
Stand-alone ener
Stand-alone ener
ram
Increment
Size (kW)
•
100
100
500
500
100
2024$
/MWh
llllllmII
124
124
63
63
25
2035$
/MWh
186
186
65
65
n/a
2024$ /
kW­
Month
22.91
21.61
26.49
14.20
15.55
27.58
2035$ /
kW­
month
40.28
37 .72
39.06
16.35
18.92
32.25
10 NREL (National Renewable Energy Laboratory). 2022. 2022 Annual Technology Baseline. Golden, CO:
National Renewable Energy Laboratory.
Avista Corp 2023 Electric IRP 5-18
Chapter 5: Distributed Energy Resources
DER Evaluation Methodology
Avista models each of the DE Rs discussed in this chapter in the same economic selection
model as other utility asset options. Avista's intent is to include all known utility costs and,
where required (i.e., Washington), known non-energy or social impacts. Recently, the
WUTC is working on a proposal11 for evaluating DERs as part of a workshop process with
the assistance of Synapse Energy Economics. Currently, the WUTC has put out a draft
proposal of the types of considerations utilities should use when conducting resource
planning activities. While this concept is currently in draft form, it does provide an
opportunity for Avista to demonstrate the types of costs and considerations used in the
evaluation of these resources. The list of options from the strawman proposal is shown in
Table 5.7 for those resources applicable to this plan.
Due to the complexity and size of the list of considerations, the answers within the boxes
are high level, where "Direct" means there is a value used within the PRiSM optimization
model for this value. "Indirect" indicates this value is included by the savings compared
to other resources; for example, if choosing energy efficiency lowers capacity needs from
other resources. Items listed as "N/A" indicate the values are not applicable to the DER.
"No" indicates the value is not included. Avista will continue to provide feedback to the
WUTC on how to address DER analysis but believes if additional non-energy values are
included for DERs the analysis must include similar cost and benefits to utility scale
assets. Further, many of the values discussed are qualitative and difficult to quantify for
use in modeling.
11 Washington Cost-Effectiveness Test for Distributed Energy Resources, Straw Proposal for the Primary
Test, November 7, 2022. Docket UE-210804.
Avista Corp 2023 Electric IRP 5-19
Chapter 5: Distributed Energy Resources
Table 5.7: DER Cost & Benefit Impacts
Category Impact Energy Demand Solar Storage
Efficiency Response
Generation Energy Generation Direct Direct Direct Direct
Capacity Indirect Indirect Direct Direct
Environmental Compliance Indirect Indirect Indirect Indirect
Clean Enerqy Compliance Indirect Indirect Direct Indirect
Market Price Effects Direct Direct Direct Direct
Ancillary Services Indirect Indirect Direct Direct
Transmission Transmission Capacity Direct No Direct Direct
Transmission System Losses Direct Direct Direct Direct
Distribution Distribution Cost Direct Direct Direct Direct
Distribution Voltaqe No No Indirect Indirect
Distribution System Losses Direct Direct Direct Direct
General Financial Incentives N/A Direct No No
Program Admin Cost Direct Direct Direct No
Utility Performance Incentives No No No No
Compensation Mechanisms No No No No
Credit and Collection Costs Indirect Indirect Indirect Indirect
Risk No No No No
Reliability No No No No
Resilience No No No No
Host Measure Costs Direct Direct N/A N/A
Customer Transaction Costs Direct Direct N/A N/A
Energy Interconnection Fees N/A N/A Direct Direct
Impacts Risk No No No No
Reliability No No No No
Resilience No No No No
Other Fuels n/a No No No
Tax Incentives Direct No Direct Direct
Host Water No No No No
Customer Asset Value Indirect No No No
Non-Energy Productivity Direct No No No
Impacts Economic well-being Direct No No No
Comfort Direct No No No
Health & Safety Direct No No No
Empowerment & Control No No No No
Satisfaction & Pride Indirect No No No
Low-Income NEis Direct No No No
Societal Greenhouse Gas Emissions Direct Indirect Indirect Indirect
Impacts Other Environmental No No
Public Health Direct No Direct Direct
Economic & Jobs Direct No Direct Direct
Resilience No No No No
Energy Security No No No No
Avista Corp 2023 Electric IRP 5-20
Chapter 5: Distributed Energy Resources
DER Potential Study
As part of the Washington CEIP approval process12, Avista agreed to conduct a
distribution level analysis of DER opportunities within its Washington service territory.
This includes a distribution feeder level analysis of future availability and likely adoption
of resources and load changes. The completed analysis will be available for the 2025 IRP
and used in future distribution planning activities. Currently, Avista plans to meet this
requirement by using outside consulting assistance (Applied Energy Group) with
experience conducting such an analysis. The planned work will cover the following and
include additional analysis for Named Community potential taking out income limitations:
• Electric Vehicles
o Local charging: light, medium, heaving duty
o Charging related to interstate travel
• New Generation & Storage
o Residential and commercial solar
o Residential and commercial storage
o Other renewables (i.e., wind, small hydro, fuel cell, internal combustion
engines)
o Combined heat and power
• Load Management
o Energy Efficiency
o Demand Response
Avista envisions five tasks for this project following the schedule below shown in Table
5.8. As part of this plan includes presenting preliminary results to technical and equity
advisory groups to get feedback on the results prior to finalization. For energy efficiency
and DR, Avista will work with AEG to apply its potential studies discussed in this chapter
to the local level by feeder following a similar schedule as shown for other resources.
12 Condition 14: Avista will include a Distributed Energy Resources (DERs) potential assessment for each
distribution feeder no later than its 2025 electric IRP. Avista will develop a scope of work for this project no
later than the end of 2022, including input from the IRP TAC, EEAG, and DPAG. The assessment will
include a low-income DER potential assessment. Avista will document its DER potential assessment work
in the Company's 2023 IRP Progress Report in the form of a project plan, including project schedule, interim
milestones, and explanations of how these efforts address WAC 480-100-620(3)(b)(iii) and (iv).
Avista Corp 2023 Electric IRP 5-21
Chapter 5: Distributed Energy Resources
Table 5.8: DER Potential Study Schedule
Number Due Date Deliverable
Task 1 July 2023 (a) A survey of other utility or other entity efforts to conduct similar DER
potential studies. The study shall include comparison of the other
utility's size, rates, climate, and customer demographics.
(b) A summary of best practices for development of future adoption of
new DER technologies.
(c) An overview of Avista's current DER resources (i.e., 2022 baseline).
Task 2 September A description of the methodology used to develop the estimates for
2023 each DER, related scenarios and electric vehicles.
Task 3 Draft March (a) Matrix including each feeder and the quantity of each electric
2024 vehicle by class. An hourly load shape for each vehicle class, by
weekday type and month. A second matrix is required for feeders
Final May within named communities.
2024 (b) Matrix including each feeder and the amount of DER resources in
kW and/or kWh for each resource type by year and customer class.
The summary shall also include an estimated portion of the resource
opportunity providing ancillary services13 along with adjustments for
higher potential due to income limits from named communities.
Task 4 Q1 2024 Present draft results of study to Avista's Advisory Committees for
comment and question. Advisory committees may include: Electric
Integrated Resource Planning Technical Advisory Committee, Energy
Efficiency Advisory Group, and the Distribution Planning Advisory
Group.
Task 5 Draft April (a) Final report including tasks 1 through 4,
2024 (b) Summary of comments and suggestions from non-Avista parties
Final June 1, and how they are addressed in the final report,
2024 (c) Recommendations for future studies,
(d) Documentation of methods and procedures to transition Avista to
be able to update these forecasts for future use.
13 Ancillary services include the resource's ability to provide regulation, load following, operating reserves,
and voltage support.
Avista Corp 2023 Electric IRP 5-22
Chapter 6: Supply-Side Resource Options
6. Supply-Side Resource Options
Avista evaluates several different generation options including Distributed Energy
Resources (DER) and utility-scale resource options to meet future resource deficits. This
Progress Report evaluates upgrading existing resources, constructing, and owning new
generation facilities, and/or contracting with other energy companies. This section
describes the costs and characteristics of resource options Avista is considering in the
2023 IRP. The options are mostly generic, as actual resources are typically acquired
through competitive processes such as a Request for Proposal (RFP). This process may
yield resources differing in size, cost, and operating characteristics due to siting,
engineering, or financial requirements, and it also may reveal existing resource options
available in the region.
Section Highlights
• Solar, wind, and other renewable resource options are modeled as Purchase
Power Agreements (PPA) instead of utility ownership.
• Future competitive acquisition processes might identify different technologies
available to Avista at a different cost, size or operating characteristics and may
include existing generation options.
• Inflation Reduction Act tax incentives are included in resource costs.
• Avista models several energy storage options including pumped storage hydro,
lithium-ion, vanadium flow, zinc bromide flow, liquid air, hydrogen, iron-oxide,
and ammonia.
Assumptions
Resource options within this analysis include both commercially available resources and
future resource technology options with a strong likelihood of commercial availability. The
analysis does not include theoretical or technologies in pre-commercial phases. Resource
opportunities must be located within or near Avista's service territory with verifiable costs
and generation profiles priced as if Avista developed and owned the generation or
acquired generation from Independent Power Producers (IPPs) through a PPA.
Resources using PPAs rather than ownership include pumped hydro storage, wind, solar
(with and without storage), geothermal, and nuclear. Avista modeled these resource types
as PPAs since historically IPPs financially capture tax benefits for these resources earlier
and can leverage lower cost of capital, thereby reducing the cost to customers.
Resource options assuming utility ownership include natural gas-fired combined cycle
combustion turbines (CCCT), simple cycle combustion turbines (SCCT), natural gas-fired
reciprocating engines, ammonia-fired SCCT, energy storage, hydrogen fuel cell,
biomass, and thermal unit upgrades. Upgrades to coal-fired units were not included or
considered. Modeling resources as PPAs or ownership does not preclude the utility from
acquiring new resources in other manners but serves as a cost estimate for the new
resources. Several other resource options described later in the chapter are not included
in the portfolio analysis but are discussed as potential resource options since they may
appear in a future request for resources acquisition.
Avista Corp 2023 Electric IRP 6-1
Chapter 6: Supply-Side Resource Options
It is difficult to accurately model potential contractual arrangements with other energy
companies as an option in the plan specifically for existing units or system power, but
such arrangements may offer a lower customer cost when a competitive acquisition
process is completed. Avista plans to use competitive RFP processes for resource
acquisitions where possible to ensure the lowest cost resource is acquired for customers.
However, another acquisition process may yield better pricing on a case-by-case basis,
especially for existing resources available for shorter periods. Avista uses the IRP, RFPs,
and market intelligence to determine and validate its upgrade alternatives when
evaluating upgrades to existing facilities. Upgrades typically require competitive bidding
processes to secure contractors and equipment.
The costs of each resource option do not include the cost related to upgrading the
transmission or distribution system described in Chapter 7 or third-party wheeling costs.
All costs are considered at the busbar. Avista excludes these costs to allow for consistent
cost comparison as resource costs at specific locations are highly dependent on the
location in relation to Avista's system. These costs are included when Avista evaluates
the resources for selection in an RFP and within the IRP's portfolio analysis. All costs are
levelized by discounting nominal cash flows by the 6. 7 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 2023 nominal dollars unless otherwise noted. All cost and
operating characteristic assumptions for generic resources and how PPA pricing were
calculated are available in Appendix F and are also available on Avista's website.
Avista relies on several sources of resource costs including the National Renewable
Energy Laboratory (NREL), Lazard, Northwest Power and Conservation Council (NPCC
or Council), press releases, regulatory filings, internal analysis, other publicly available
studies, developer estimates and Avista's experience with certain technologies to develop
its generic resource assumptions. In addition, Avista's 2022 All-Source RFP and 2020
Renewable RFP were utilized to ensure assumed costs for solar, wind , solar/storage, and
other resource options were in line with pricing available from actual projects within or
near Avista's service territory.
Levelized resource costs illustrate the differences between generator types. The values
show the cost of energy if the plants generate electricity during all available hours of the
year. In actual operation, plants do not operate at 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 technologies.1 Without this
separation of costs, resources operating infrequently during peak-load periods would
appear more expensive than baseload CCCTs, even though peaking resources are lower
total cost when operating only a few hours each year. Avista levelizes the cost using the
production capability of the resource. For example, a natural gas-fired turbine is available
92 to 95 percent of the time when accounting for maintenance and forced outages. Avista
divides the cost by the amount of megawatt hours the machine is available to produce
1 Storage technologies use a $ per kWh rather than $ per kW because the resource is both energy and
capacity limited.
Avista Corp 2023 Electric IRP 6-2
Chapter 6: Supply-Side Resource Options
energy. For resources limited by fuel availability such as solar or wind 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 qualifying capacity credits (QCC) for each resource
option.2 Table 6.1 compares the levelized costs of different resource types over a 30-year
asset life.
Distributed Energy Resources
This IRP includes several distributed energy resource options. DERs are both supply­
and demand-side resources located at either the customer location or at a utility­
controlled location on the distribution system. Demand side DERs include energy
efficiency and demand response (DR). Additional details about these program options
are found in Chapter 5. In addition to modeled demand-side DER options, Avista includes
forecasts for customer-owned solar and electric vehicles as part of its load forecast
discussed in Chapter 2.
In addition to demand-side DERs, supply-side resource options include small scale solar
and battery storage. Avista includes specific cost estimates for smaller scale projects
described later in this chapter along with the energy, capacity, and ancillary service
benefits traditional utility scale projects offer. Due to the location, additional benefits such
as line loss savings over alternative utility scale projects are also included. Other
locational benefits may also be credited to the project if it alleviates distribution
constraints. Projects on the customer system may also provide reliability benefits to the
specific customer.
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 plant emissions. This
analysis models CCCTs as a "one-on-one" (1x1) configuration with duct fire capability,
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 180 MW and 312 MW each depending on configuration and location.
Cooling technology is a major cost driver for CCCTs. Depending on water availability,
lower-cost water 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. Avista assumes water is available for plant cooling
based on its internal analysis, but only enough water rights for a hybrid system utilizing
the benefits of combined evaporative and convective technologies.
This analysis includes one CCCT plant option sized at 312 MW in 1x1 configuration with
a duct fire capability. Avista reviewed several CCCT technologies and sizes and selected
2 Peak credit is the amount of capacity a resource contributes at the time of system one-hour peak load.
Avista Corp 2023 Electric IRP 6-3
Chapter 6: Supply-Side Resource Options
this plant as the best fit for the needs of Avista's customers. If Avista were to pursue a
new CCCT, a competitive acquisition process will allow analysis of other CCCT
technologies and sizes at both Avista's preferred and other locations. It is also possible
Avista could acquire an existing CCCT resource from one of the many units in the Pacific
Northwest.
The most likely location for a new CCCT is in Idaho, mainly due to Idaho's lack of an
excise tax on natural gas consumed for power generation, a lower sales tax rate relative
to Washington and no state taxes or fees on the emission of carbon dioxide. 3 CCCT sites
likely would be on or near Avista's transmission system to avoid third-party wheeling
costs. Another advantage of siting a CCCT resource in Avista's Idaho service territory is
access to relatively low-cost natural gas on the GTN pipeline. Avista already secured a
site with these potential connection points if it needs to add additional capacity from a
CCCT or other technology.
Combined cycle technology efficiency has improved since Avista's current CCCT
generating fleet entered service with heat rates as low as 6,400 Btu/kWh for a larger
facility and 6,700 for smaller configurations. Duct burners can add additional capacity with
heat rates in the 7,200 to 8,400 Btu/kWh range.
The anticipated capital costs for the modeled CCCTs, located in Idaho on Avista's
transmission system with AFUDC on a greenfield site, are approximately $1,315 per kW
in 2023 dollars. These estimates exclude the cost of transmission and interconnection.
Table 6.1 shows levelized plant cost assumptions split between capacity and energy for
the combined cycle option discussed here, and the natural gas peaking resources
discussed in the next section. The costs include firm natural gas transportation, fixed and
variable O&M and transmission. Table 6.2 summarizes key cost and operating
components of natural gas-fired resource options. With competition from alternative
technologies and the need for additional flexibility for intermittent resources, it is likely to
put downward pressure on future CCCT costs.
Natural Gas-Fired Peakers
Natural gas-fired SCCTs and reciprocating engines, or peaking resources, provide low­
cost capacity capable of providing energy as needed. Technological advances coupled
with a simpler design relative to CCCTs allow SCCTs to start and ramp quickly, providing
regulation services and reserves for load following and variable resources integration.
This analysis models frame and reciprocating engine technologies only, other
technologies would be considered in resource acquisition. Peakers have different load
following abilities, costs, generating capabilities, and energy-conversion efficiencies. The
levelized cost for each of the technologies is in Table 6.1. Table 6.2 shows cost and
operational characteristics based on internal engineering estimates.
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 3.852 percent. Washington also has higher sales
taxes and carbon dioxide mitigation fees for new plants.
Avista Corp 2023 Electric IRP 6-4
Chapter 6: Supply-Side Resource Options
Firm natural gas fuel transportation is an electric generation reliability issue with FERG
and is also the subject of regional and extra-regional forums. For this plan, 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.
This assumption is being reviewed on a regular basis as the amount of firm and non-firm
natural gas transportation changes over time. 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 peak demand times, on­
site fuel oil or nearby storage such as liquefied natural gas in tanks or trailers.
Table 6.1 : Natural Gas-Fired Plant Levelized Costs
Plant Name/Location Total $/kW-Yr Variable Winter
$/MWh Capability $/MWh Capacity
(MW)
7F .04 CT Frame Greenfield (Idaho) 60.3 101.8 48.3 180 7F .04 CT Frame Greenfield (Washington) 62.3 104.3 50.0
Reciprocatinq Enqine (ICE) Machine (Idaho) 61.5 152.4 43.6 185 Reciprocatinq Enqine (ICE) Machine (Washinqton) 63.4 156.2 45.0
NG CCCT (1x1 w/DF) (Idaho) 57.6 183.3 36.1 312 NG CCCT (1x1 w/DF) (Washinqton) 59.2 187.1 37.2
Table 6.2: Natural Gas-Fired Plant Cost and Operational Characteristics4
Item Capital Fixed Heat Variable Total Total
Cost with O&M Rate O&M Project Cost
AFUDC ($2023/ (Btu/ ($/MWh) Size (Mil$-
($2023/kW) kW-yr) kWh) (MW) 2023)
7F .04 CT Frame Greenfield 822 155 (Idaho)
7F .04 CT Frame Greenfield 5.2 10,040 3.10 180
(Washington) 845 159
Reciprocating Engine (ICE) 1,315 244 Machine (Idaho)
Reciprocating Engine (ICE) 5.2 8,190 5.93 185
Machine (Washinqton) 1,349 251
NG CCCT (1x1 w/DF) (Idaho) 1,315 410
NG CCCT (1x1 w/DF) 1,349 30.5 6,820 4.75 312 421 (Washinqton)
Wind Generation
Wind resources benefit from having no direct em1ss1ons or fuel costs but are not
dispatchable to meet load. Avista models four general wind location options in this plan :
Montana, Eastern Washington, the Columbia River Basin, and offshore. Configurations
4 Costs based on Idaho. Washington 's costs would be slightly higher due to a higher sales tax rate of 8.9%
compared with Idaho's 6.0% rate.
Avista Corp 2023 Electric IRP 6-5
Chapter 6: Supply-Side Resource Options
of wind facilities are changing given regional transmission limitations, federal tax credits,
low construction prices and the potential for storage. These factors allow for sites being
built with higher capacity levels than the transmission system can currently integrate.
When the wind facilities generate additional MWh above the physical transmission
limitations,5 the generators typically feather (i.e., stop or reduce generation) or store
energy using onsite energy storage. At this time, Avista is not modeling wind with onsite
storage or wind facilities with greater output capabilities than can be integrated on the
transmission system. Avista's modeling process allows for storage to be sited at a wind
facility if cost effective.
On-shore wind capital costs, including construction financing, for various start dates is
shown in Table 6.3 as well as fixed O&M costs in kW-yr. for various years in Table 6.4.
Fixed O&M does not include indirect charges to account for the inherent variation in wind
generation often referred to as variable wind integration. The cost of wind integration
depends on the penetration and diversity of wind resources in A vista's balancing authority
and the market price of power.
Wind capacity factors in the Northwest range between 32 and 35 percent depending on
location and in the 43 to 51 percent range in Montana and offshore locations. This plan
assumes Northwest wind (Washington and Oregon) has a 34 percent average capacity
factor, while Montana and offshore wind have average capacity factors of 43 and 50
percent, respectively. 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 section for details in Chapter 8).
Offshore wind has potential for higher annual capacity factors (51 percent), but
development and operating costs are higher. At the time of this plan's analysis,
developers have not been offering an offshore product in the Pacific Northwest and are
still in the early stages of permitting and cost estimation. The pricing and costs are
estimates based on early proposals in California and Oregon.
As discussed above, levelized wind costs change substantially due to the capacity factor
but can be impacted even more from tax incentives and the ownership structure of the
facility. Table 6.5 shows the nominal levelized prices with different start dates for each
modeled location. These price estimates assume a 20-year PPA with a flat pricing
structure, includes costs associated with the cost of the PPA, excise taxes, commission
fees, and uncollectables6 to customers. These costs do not include the transmission costs
for either capital investment or wheeling purchases or integration costs. If a PPA is
selected in Avista's resource strategy, the model assumes the PPA will extend through
at least 2045.
5 If transmission is limited due to contractual reasons, an additional option is to buy non-firm transmission
to move the power.
6 Uncollectables refer to additional revenue collected from customers to cover the payments not received
from other customers.
Avista Corp 2023 Electric IRP 6-6
Chapter 6: Supply-Side Resource Options
Photovoltaic Solar
Avista models solar system configurations as resource options, whereas the under 5 MW
distributed systems are discussed in Chapter 5, the utility scale options are discussed
here. Utility-scale on-system solar facilities assume a minimum capacity of 100 MW to
take advantages of economies of scale and single axis systems. There are also two
locations for resource selection, the first is local on-system resources in areas within
Avista's transmission system with higher capacity factor potential, and a second option
further south either in Oregon or Idaho, requiring transmission acquisition . Avista expects
other locations to participate in future RFPs. Tables 6.3 and 6.4 show capital and fixed
O&M forecasts for these resources and the levelized prices for a 20-year PPA is shown
in Table 6.5. These costs do not include transmission costs associated with either new
construction or wheeling purchases or integration costs.
Table 6.3: Forecasted Solar and Wind Capital Cost ($/kW)
Year Utility Scale NW Wind Montana Off-Shore
Solar (On-System) Wind Wind
2025 1,201 1,460 1,649 5,535
2030 1,026 1,283 1,494 5,697
2035 1,092 1,359 1,594 6,021
2040 1,161 1,435 1,697 6,447
2045 1,231 1,512 1,804 6,954
Table 6.4: Forecasted Solar and Wind O&M ($/kW-yr.)
Year Utility Scale NW Wind Montana Off-Shore
Solar (On-System) Wind Wind
2025 21 .55 48.60 48.60 97.01
2030 20.14 51.54 51.54 99.40
2035 21.72 55.31 55.31 104.23
2040 23.40 59.27 59.27 110.67
2045 25.19 63.40 63.40 118.44
Table 6.5: Levelized Solar and Wind Prices ($/MWh)
Year Utility Scale NW Wind Montana Off-Shore
Solar (On-System) Wind Wind
2025 33.51 42.35 32.69 124.42
2030 20.17 30.64 23.07 120.87
2035 43.81 60.80 53.59 151 .69
2040 44.30 59.99 53.59 155.03
2045 43.89 57.17 52.08 157.64
Avista Corp 2023 Electric IRP 6-7
Chapter 6: Supply-Side Resource Options
Solar with Energy Storage (Lithium-Ion Technology)
As previously discussed, storage paired with energy storage lowers cost due to sharing
of local infrastructure, it can also directly shift energy deliveries, manage intermittent
generation, use common equipment, increase peak reliability, and can prevent energy
oversupply.
Lithium-ion technology prices are declining (absent recent price spikes related to supply
chain disruption) and will likely continue to fall due to increasing manufacturing levels and
product enhancements. Avista estimates the cost three storage level types in Table 6.6
for solar PPAs, these costs are based on 100 MW solar facility. Avista modeled one two­
hour duration and two four-hour duration options. Avista's experience with solar
generation from its 19.2 MW Adams-Neilson PPA shows significant energy variation due
to cloud cover and on-site storage could be beneficial, but at this time other resources
can provide this service at a lower cost. For this analysis, Avista considers the benefits
for reducing the variable generation integration costs and enhanced resource adequacy
of the storage device within the resource selection model. Currently, due to the complexity
and range of potential storage configurations, the analysis considers only the four-hour
and two-hour designs. In addition, Avista's modeling of solar plus storage allows the
storage device to use grid power.
Table 6.6: Additional Levelized Cost for Combined Lithium-Ion Storage Solar
Facility ($/kW-month)
Year 100 MW/ 100 MW/ S0MW/
400 MWh 200 MWh 200 MWh
2025 11.8 7.2 4.1
2030 11.1 7.1 4.0
2035 13.5 8.6 4.8
2040 13.7 8.8 4.8
2045 13.7 8.8 4.6
Stand-Alone Energy Storage
Energy storage resources are gaining significant traction to meet short term capacity
needs in the western U.S. Energy storage does not create energy but shifts it from one
period to another in exchange for a portion of the energy stored. Avista modeled several
energy storage options including pumped hydro storage, lithium-ion, vanadium flow, zinc
bromide flow, liquid air, and iron oxide. In addition to the technology differences, Avista
also considers different energy storage durations for each technology. Pricing for energy
storage is rapidly changing due to the technology advancements. In addition to changing
prices for existing technologies, new technologies are entering the storage space. The
rapid change in pricing and new available technologies justifies the need for frequent
updates to the IRP analysis. Passage of the 2022 Inflation Reduction Act (IRA) creates
energy tax credits for all storage technologies through 2032.
Another challenge with storage concerns 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
Avista Corp 2023 Electric IRP 6-8
Chapter 6: Supply-Side Resource Options
distribution expansion, where the technology can alleviate conductor overloading and
short duration load demands rather than adding physical line/transmission capacity.
Storage cannot be shown in $ per MWh as with other generation resources because
storage does not create energy, but rather stores it with losses. The analysis shown in
Figure 6.1 illustrates the cost differences between the technologies when capital cost is
divided by duration of storage but does not consider the efficiency of the storage process
or the pricing of the energy stored. This analysis is performed in the resource selection
process. Figure 6.1 summarizes the storage technologies based on upfront capital cost
and duration using costs in 2030 dollars.
Figure 6.1: Storage Upfront Capital Cost versus Duration
Pumped Hydro (8.5 hr)
Dist Scale Lithium-Ion (4 hr)
Dist Scale Lithium-Ion (8 hr)
Zinc Bromide (4 hr)
Vanadium (4 hr)
Lithium-Ion {4hr)
Pumped Hydro (16 hr)
Lithium-Ion (8 hr)
Lithium-Ion (16 hr)
Hydrogen Fuel Cell (40 hr)
Pumped Hydro (24 hr)
Liquid Air (16 hr)
Iron Oxide (100 hr)
Frame CT+ Ammonia (350 hr)
Pumped Hydro Storage
$0 $100 $200 $300 $400 $500 $600 $700
$ kW per Hour of Capacity
The most prolific energy storage technology currently used in both the U.S. and the world
is pumped hydro. This technology requires the use of two or more water reservoirs with
different elevations. When prices or load are low, water is pumped to a higher reservoir
and released during higher price or load periods. This technology may also help meet
system integration issues from intermittent generation resources. Currently only one of
these projects exists in the northwest and several more are in various stages of the
permitting process. An advantage with pumped hydro is the technology has a long service
life and is a technology Avista is familiar with as a hydro generating utility. The greatest
disadvantages are large capital costs and long-permitting cycles.
The technology has good round trip efficiency rates, Avista assumes 80 percent for most
options. When projects are developed, they are designed to utilize the amount of water
storage in each reservoir and the generating/pump turbines are sized for how long the
capacity needs to operate. Avista models the technology with three different durations:
8.5, 16, and 24 hours. These durations indicate the number of hours the project can run
Avista Corp 2023 Electric IRP 6-9
Chapter 6: Supply-Side Resource Options
at full capacity. The pricing and durations of these facilities are based on projects currently
being developed in the Northwest. As an energy-limited system, Avista includes different
duration times to ensure resources have sufficient energy to provide reliable power over
an extended period in addition to meeting single hour peaks. The complete range in
levelized cost for pumped hydro is shown in Table 6.7. Options also include a $0.58 per
MWh (escalating with inflation) variable payment for each MWh generated.
Table 6.7: Pumped Hydro Options Cost ($/kW-month)
Year 8.5 hours 16 hours 24 hours
2025 45.66 39.89 36.03
2030 50.94 44.50 40.20
2035 56.80 49.62 44.82
2040 63.33 55.32 49.97
2045 70.61 61.68 55.71
Lithium-Ion Batteries
Lithium-ion technology is one of the fastest growing segments of the energy storage
space. This discussion focuses on using energy storage as a stand-alone resource rather
than coupled with solar as discussed earlier. Stand-alone lithium-ion assumes a utility
owned asset for modeling purposes, but it could be acquired through a PPA as well with
two 10-year cycles for a 20-year life. Fixed O&M costs include replacement cells to
maintain the energy conversion efficiency and capacity for this storage option. Estimated
costs include federal tax credits passed as part of the 2022 IRA.
The lithium-ion technology is an advanced battery using ionized lithium atoms in the
anode to separate their electrons. This technology can carry high voltages in small spaces
making it a preferred technology for mobile devices, power tools, and electric vehicles.
The large manufacturing sector of the technology is driving prices lower permitting the
construction of utility scale projects.
Avista modeled five stand-alone configurations for lithium-ion batteries. Two DER small­
scale sizes (<5 MW) with four-and eight-hour durations for modeling the potential for use
on the distribution system and three larger systems (25 MW) including four-and eight­
hour durations as well as a theoretical 16-hour configuration were derived from publicly
available energy consultant sources. Figure 6.2 show the forecast for each of the sizes
and durations considered . Avista classifies the four-hour battery as the standard
technology with a capital cost of $1 ,423 per kW in 2023 dollars. Avista assumes an annual
Fixed O&M cost of $149 per kW-year in 2023 for the four-hour technology.
Avista Corp 2023 Electric IRP 6-10
$6,000
$5,000
$4,000
~ .:.:: $3,000 ...
Cl) a.
~
$2,000
$1,000
$0
Chapter 6: Supply-Side Resource Options
Figure 6.2: Lithium-ion Capital Cost Forecast
'--------
-Distribution Scale 4hr -Distribution Scale 8hr Utility Scale 4 hr
-Utility Scale 8 hr -Utility Scale 16 hr
M V ~ ~ ~ = ~ 0 ~ N M V ~ ~ ~ = ~ 0 ~ N M V ~ N N N N N N N M M M M M M M M M M V V V V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N
Storage technology is often displayed differently to illustrate the cost since it is not a
traditional capacity resource. Table 6.8 shows levelized cost per kW-month for each
configuration. This calculation factor levelizes the cost for the capital, O&M, and
regulatory fees including capital reinvestments over 20 years divided by the capacity.
These costs do not consider the variable costs, such as energy purchases.
Table 6.8: Lithium-Ion Levelized Cost ($/kW-month)
Year Utility Scale Utility Scale Utility Scale
4 hour 8 hour 16 hour
2025 11.57 20.47 38.26
2030 10.74 18.31 33.44
2035 14.82 24.67 45.07
2040 15.05 24.69 45.09
2045 14.99 24.23 44.25
Flow Batteries
This plan models vanadium and zinc bromide flow batteries options. Other technologies
are beginning to enter the marketplace. Flow batteries have the advantage over lithium­
ion of not degrading over time leading to longer operating lives. The technology consists
of two tanks of liquid solutions flowing adjacent to each other past a membrane and
generate a charge by moving electrons back and forth during charging and discharging.
Avista assumed an acquisition size of 25 MW of capacity with four-hours in duration for
each technology.
Avista Corp 2023 Electric IRP 6-11
Chapter 6: Supply-Side Resource Options
Capital costs are $1 ,378 per kW for the vanadium in 2023 and nominal costs fall 15
percent by 2032. Zinc bromide's capital cost are $1,448 per kW in 2023 and similarly fall.
Fixed O&M costs are $64.78 per kW-year for vanadium and $72.88 per kW-year for zinc
bromide and increase with inflation. Round-trip efficiency for the vanadium is 70 percent
and for the zinc bromide is 67 percent. Given Avista's recent experience with vanadium
flow batteries, these efficiency rates are highly dependent on the battery's state of charge
and how quickly the system is charged or discharged. Table 6.9 shows the levelized cost
per kW-month of capacity.
Liquid Air Storage
A new technology with promise to provide long duration and long service life is liquid air
storage. This is similar to compressed air storage, but rather than compressing the air,
the air is cryogenically frozen and stored in a tank to increase storage duration capability.
The conversion process requires a liquefier to liquefy the air for storage. It is possible to
use waste heat from existing natural gas-fired turbines to increase the efficiency of
liquefying the air molecules. A round-trip efficiency of 65 percent is assumed. After the air
is stored , it can later be used by pushing the air through an air turbine .
Liquid air has not been widely used in the electric sector but relies on common technology
from other industries requiring liquefaction of gases. This experience in the technology
gives promise as a new technology that could benefit from short commercialization
periods. Avista models a 25 MW unit with 400 MWh hours of storage (16 hours) as the
resource option. Another advantage of this technology is the ability to add storage
capacity by adding more tanks while using the same turbine and liquefaction systems.
Avista estimates liquid air storage capital costs at $1,661 per kW (2023 dollars) and
increases with inflation due to the use of mature industrial technology. Fixed O&M is
$25.79 per kW-year and carries a $5.93 per MWh variable charge. The levelized cost of
the storage is estimated to be $14.40 per kW-month for 2023 and future years increase
with inflation .
Iron Oxide Storage
Another new storage technology is an iron oxide battery where energy is stored using
energy created through the oxidization process. Iron is less expensive and more readily
available than lithium-ion or other storage technology elements. This technology uses
oxygen to convert iron inside the battery to rust and later convert it back to iron. Due to
the low cost of iron compared to other elements a long-duration resource can be obtained
at similar cost to current shorter duration technologies.
This analysis assumes a 100 MW iron-oxide battery with a 36.5 percent round-trip
efficiency with 100 hours of storage or 10,000 MWh of storage. Capital costs are
estimated at $2,528 per kW (2023 dollars) and increase due to inflation. Fixed O&M is
$30 .95 per kW-year and the levelized cost of iron oxide storage is $248.21 per kW ($20.68
per kW-month) increasing for inflation in future periods. The actual costs are uncertain
given this resource is relatively new for commercial energy use.
Avista Corp 2023 Electric IRP 6-12
Chapter 6: Supply-Side Resource Options
Table 6.9: Storage Levelized Cost ($kW-Month)
Year Vanadium Zinc Iron Oxide Liquid Air
Bromide
2025 15.91 17.23 20.91 15.06
2030 16.05 17.43 21.44 16.80
2035 19.92 21 .56 29.68 25.30
2040 20.85 22.62 30.35 28.20
2045 21 .88 23.78 31 .07 31.45
Renewable "Green" Hydrogen
The idea of using green hydrogen using renewable energy to power an electrolyzer in the
energy sector has been a perennial option for the distant future. This technology is an
avenue for long-duration energy storage with the potential to store power to continuously
run for up to several days. Hydrogen would be delivered by pipeline, truck, or rail and
stored in tanks or underground caverns and then converted back to power (and water)
when needed using a fuel cell or hydrogen-fueled turbine. The ability to store hydrogen
in tanks similar to liquid air means medium term duration times can be obtained.
Significant research and development (R&D) is being dedicated to green hydrogen
technologies in transportation and other sectors which may result in reduced costs or
increased operating efficiency. It is also possible transportation and other sectors could
utilize the electric power system to create a cleaner form of hydrogen to offset gasoline,
diesel, propane, or natural gas.
Most hydrogen today uses methane-reforming techniques to remove hydrogen from
natural gas or coal. This technology is primarily used in the oil and natural gas industries
but results in similar levels of greenhouse gas emissions from the combustion of the
underlying fuels absent sequestration or carbon capture. If green hydrogen is obtained
from "clean" energy through electrolysis of water7, the amount of greenhouse gas
emissions can be greatly reduced. If renewable energy prices fall and there is an available
water supply, the operating cost of creating green hydrogen could also fall, however
capital costs would remain steady without significant technology enhancements.
Converting hydrogen back into power could be done by using a hydrogen fuel cell or
direct burning in a combustion turbine similar to natural gas-fired generation. Figure 6.3
shows the forecasted delivered price of hydrogen to a potential green hydrogen fuel
facility in Avista's service territory. The development and delivery of green hydrogen is
estimated based on the projected cost of electrolyzer technology with reduction in costs
due to scaling and access to low-cost renewable electric power and water.
7 Current estimates require 2-3 gallons of water to create 1 kilogram of hydrogen.
Avista Corp 2023 Electric IRP 6-13
E
$5.00
$4.50
$4.00
$3.50
~ $3.00
C,
0 = $2.50 ::.:::
Qi $2.00
C.
~ $1.50
$1.00
$0.50
$0.00
Chapter 6: Supply-Side Resource Options
Figure 6.3: Wholesale Green Hydrogen Costs per Kilogram
--~ . ... · 1
--------
The second step in the hydrogen concept is to convert the hydrogen back to power. For
this conversion, a 25 MW fuel cell would be assembled for utility scale needs. The
estimated capital cost for a fuel cell is $6,071 per kW with a forty-hour storage vessel plus
fixed O&M at $181.16 per kW-year (2023 dollars). Table 6.10 shows the all-in levelized
cost of hydrogen including both the fuel cell capital recovery fixed cost and the fuel cost
per MWh. Avista chose to use a fuel cell for hydrogen fuel rather then a CT, to allow for
an air emission free resource and due to the likely limitations of storing the fuel required
to operate a CT.
There are significant safety concerns relative to hydrogen to be resolved and mitigated
as hydrogen ignites more easily than gasoline or natural gas. Therefore, adequate
ventilation and leak detection are important elements in the design of a safe hydrogen
storage system. Hydrogen burns with a nearly invisible flame which requires special flame
detectors. Some metals become brittle when exposed to hydrogen, so selecting the
appropriate metal is important to the design of a safe storage system. Finally, appropriate
training in safe hydrogen handling would be necessary to ensure safe use. Appropriate
engineering along with safety controls and guidelines could mitigate the safety risk of
hydrogen but would add to the high capital and operating costs of this resource option.
Another option to generate power with hydrogen is to use it in a combustion turbine,
currently co-firing and pure hydrogen fueling is being tested. While this is a viable option ,
Avista presents a similar option below to solve storage and safety concerns below in the
ammonia turbine option.
Avista Corp 2023 Electric IRP 6-14
Chapter 6: Supply-Side Resource Options
Ammonia
A new resource option to this plan is a gas turbine fueled with "clean" ammonia8.
Ammonia could be sourced from the same electrolysis process as green hydrogen, using
either directly from a renewable energy source or from grid power and then can be
transported and stored on the generation site similar the hydrogen fuel option above.
Although, ammonia requires an additional step to the hydrogen process by adding
nitrogen to hydrogen using the Haber-Bosch process. Current estimates taking into
account the hydrogen electrolysis process estimate the round-trip efficiency of this
technology with CT for power production at 13%9, although with technology
improvements the round-trip efficiency may reach 20%. The advantage of Ammonia as a
fuel over direct hydrogen, is ammonia can be stored in larger volumes when in aqueous
form and transported in larger quantities at a lower cost. Hydrogen storage in large
quantities requires large geologic storage for hydrogen is not known to exist near Avista's
service area.
For this resource option , two 74 MW capacity combustion turbines (148 MW) using a
common 30,000 tonne storage tank could hold 52,500 MWh hours of energy storage,
enough to generate power for 350 consecutive hours at full capacity. Ammonia storage
tanks are common technology in the agriculture industry for fertilizer and modified natural
gas turbines capable of ammonia combustion are being developed by turbine
manufactures. Another advantage of this technology is the creation of "green" ammonia
for use in agriculture. This secondary use can reduce investment cost and risk to a utility
by partnering with other industries needing ammonia.
Avista estimates ammonia gas turbine capital costs at $882 per kW (2023 dollars) and
increasing with inflation due to the use of mature technology. Fixed O&M is $15.48 per
kW-year and carries a $3.10 per MWh variable charge in addition to the cost of the
ammonia. The forecasted price of ammonia is based on the hydrogen price forecast
shown in Figure 6.3 adjusted for conversion and transportation costs. Since ammonia will
be created from electric generation, the pricing of the hydrogen includes the associated
power, water, and power delivery costs. The resulting levelized fixed and operating cost
are shown in Table 6.10.
8 Using ammonia a fuel is clean from a greenhouse gas perspective, but does emit NOx as part of
combustion. Manufactures are currently working on SCR controls for these emissions, in the meantime,
Avista assumes 0.015 lbs per mmbtu of combustion for this emission.
9 This is based on the assumption 1 tonne of ammonia requires 13.9 MWh of power from the upstream
process of electrolysis, desalination , pressure swing absorber, storage, and synthesis loops. Sagel,
Rouwenhorst, Faria, Green ammonia enables sustainable energy production in small island developing
states: A case study on the island of Curacao, 2022.
Avista Corp 2023 Electric IRP 6-15
Chapter 6: Supply-Side Resource Options
Table 6.10: Hydrogen Based Resource Option Costs
Hydrogen Fuel Cell Ammonia Turbine
Year Fixed Cost Fuel & Variable Fixed Cost Fuel & Variable
($/kW-month) Cost ($/MWh) ($/kW-month) Cost ($/MWh)
2025 86.78 139.38 11.46 257.79
2030 96.80 105.60 12.78 198.47
2035 107.93 90.77 14.25 173.23
2040 120.33 83.35 15.89 161.49
2045 134.17 84.76 17.71 165.63
Woody Biomass Generation
Woody biomass generation projects use waste wood from lumber mills or forest
management and are considered renewable and a "clean" resource. In the biomass
generation process, a turbine converts boiler-created steam into electricity. A substantial
amount of wood fuel is required for utility-scale level generation. Avista's 50 MW Kettle
Falls Generation Station consumes over 350,000 tons of wood waste annually or about
48 semi-truck loads of wood chips per day. It typically takes 1.5 tons of wood to make
one megawatt-hour of electricity but varies with the moisture content and quality of the
fuel. The viability of another Avista biomass project depends on the long-term availability,
transportation needs and cost of the fuel supply. Unlike wind or solar, woody biomass can
be stockpiled and stored for later use. Many announced biomass projects fail due to the
lack of a reliable long-term fuel source.
Based on market analysis of fuel supply and expected use of biomass facilities, a new
facility could be a wood-fired peaker. With high levels of intermittent renewable
generation , a wood-fired peaker could generate during low renewable output months or
days. The capital cost for this type of facility would be $4,907 per kW plus O&M amounts
of $29.66 per kW-year for fixed costs and $3.62 per MWh of variable costs (2023 dollars).
The levelized cost is $647.95 per kW-year ($54.00 per kW-month) for a 2023 project plus
fuel and variable O&M costs.
Geothermal Generation
Geothermal energy provides predictable capacity and energy with minimal greenhouse
gas emissions (zero to 200 pounds per MWh). Some forms of geothermal technology
extract steam from underground sources to run through power turbines on the surface
while others utilize an available hot water source to power an Organic Rankine Cycle
installation. Due to the geologic conditions of Avista's service territory, no geothermal
projects are likely to develop locally. Geothermal energy often struggles to compete
economically due to high development costs stemming from having to drill several holes
thousands of feet below the earth's crust with no guarantee of reaching useable
geothermal resources. Ongoing geothermal costs are low, but the capital required for
locating and proving a viable site are significant. The cost estimate for a future geothermal
PPA is $54.03 per MWh in 2023 at the busbar.
Avista Corp 2023 Electric IRP 6-16
Chapter 6: Supply-Side Resource Options
Nuclear
Avista includes nuclear power options as another "clean" fuel resource option, but given
the uncertainty of their economics, regional political issues with the technology, U.S.
nuclear waste handling policies and Avista's modest needs relative to the size of modern
nuclear plants Avista is unlikely to select a nuclear project in its preferred portfolio even if
economic. Nuclear resources could be in Avista's future only if other utilities in the
Western Interconnect incorporate nuclear power into their resource mix and offer Avista
a PPA or if cost effective small-scale nuclear plants become commercially available.
The viability of nuclear power could change as national policy priorities focus attention on
decarbonizing the nation's energy supply. The limited amount of recent nuclear
construction experience in the U.S. makes estimating construction costs difficult. Cost
projections are from industry studies, recent nuclear plant license proposals and the small
number of projects currently under development. Modular nuclear design could increase
the potential for nuclear generation by shortening the permitting and construction phase
and making these traditionally large projects a better fit to the needs of smaller utilities.
Given this possibility, Avista included an option for small scale nuclear power. The
estimated cost for nuclear per MWh on a levelized basis in 2030 is $138.78 per MWh
assuming capital costs of $7,574 per kW (2023 dollars) as a PPA.
Other Generation Resource Options
Resources not specifically included as options in this analysis include cogeneration,
landfill gas, anaerobic digesters, and central heating districts. This plan does not model
these resource options explicitly but continues to monitor their availability, cost, and
operating characteristics to determine if state policies change or the technology becomes
more economically viable.
Exclusion from the analysis does not automatically exclude non-modeled technologies
from Avista's future resource portfolio. The non-modeled resources can compete with
resources identified in the resource strategy through competitive acquisition processes
when a resource shortage is known , and the Company seeks resources to fill those
needs. Competitive acquisition processes identify technologies to displace resources
otherwise included in the resource strategy. Another possibility is acquisition through a
PURPA contract. PURPA allows developers to sell qualifying power to Avista at set prices
and terms10 outside of the RFP process.
Landfill Gas Generation
Landfill gas projects generally use reciprocating engines to burn methane gas collected
at landfills. The costs of a landfill gas project depend on the site specifics. The Spokane
area had a project at one of its landfills, but it was retired after the fuel source depleted to
an unsustainable level. Much of the Spokane area uses the Spokane Waste to Energy
Plant instead of landfills for solid waste disposal. Using publicly available costs and the
NPCC estimates, landfill gas resources are economically promising, but are often limited
in their size, quantity, and location. Many landfills are considering cleaning the landfill gas
to create pipeline quality gas due to low wholesale electric market prices. This form of
10 Rates, terms, and conditions are available at www.avistautilities.com under Schedule 62.
Avista Corp 2023 Electric IRP 6-17
Chapter 6: Supply-Side Resource Options
renewable natural gas has become an option for utilities to offer a renewable gas
alternative to customers. This form of gas and the duration of the supply depends on the
on-going disposal of trash, otherwise the methane could be depleted in six to nine years.
Anaerobic Digesters (Manure or Wastewater Treatment)
The number of anaerobic digesters is increasing in the Northwest. These plants typically
capture methane from agricultural waste, such as manure or plant residuals, and burn the
gas in reciprocating engines to power generators or directly inject a cleaned fuel into the
natural gas pipeline. These facilities tend to be significantly smaller than most utility-scale
generation projects and are often less than five megawatts . Most digester facilities are
located at large dairies and cattle feedlots.
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. Due to the ability to produce pipeline
quality gas these resources have also shifted to selling renewable natural gas.
Small Cogeneration
Avista has few industrial customers with loads large enough to economically support a
cogeneration project. If an interested customer developed a small cogeneration project,
it could provide benefits including reduced transmission and distribution losses, shared
fuel , capital, and emissions control costs, as well as credit toward Washington's EIA
efficiency targets.
Another potentially promising option is natural gas pipeline cogeneration. This technology
uses waste-heat from large natural gas pipeline compressor stations. Few compressor
stations exist in Avista's service territory, but the existing compressors in the Company's
service territory have potential for this generation technology. A big challenge in
developing any new cogeneration project is aligning the needs of the industrial facility
with the utility need for power. The optimal time to add cogeneration is during the creation
or retrofit of an industrial process, but the retrofit may not occur when the utility needs
new capacity. Another challenge to cogeneration is estimating costs when host
operations drive costs for a project. The best method for the utility to acquire this
technology is probably through the PURPA process or through a future RFP.
Coal
New coal-fired plants are extremely unlikely due to current policy, emission performance
standards and the shortage of utility scale carbon capture and storage projects. The risks
associated with future carbon legislation and projected low natural gas and renewables
costs make investments in this technology highly unlikely. It is possible in the future there
will be permanent carbon capture and sequestration technology at price points to
Avista Corp 2023 Electric IRP 6-18
Chapter 6: Supply-Side Resource Options
compete with alternative fuels. Avista will continue to monitor this development for future
IRPs.
Heating Districts
Historically heating districts were preferred options to heat population dense city centers.
This concept relies on a central facility to either create steam or hot water then distribute
via a pipeline to buildings to provide end use space and water heating . Historically, Avista
provided steam for downtown Spokane using a coal-fired steam plant. This concept is still
used in many cities and college campuses in the U.S. and Europe. Developing new
heating districts requires the right circumstances, partners, and long-term vision.
These requirements recently came together in a new concept of central heating districts
being tested by a partnership between Avista and McKinstry in the Spokane University
District, also called the Eco-District. The Hub facility contains a central energy plant to
generate, store and share thermal and electrical energy with a combination of heat
pumps, boilers, chillers, thermal, and electrical storage. The Hub controls all electric
consumption for the campus and balances this against the needs of both the development
and the grid. Future buildings within the district will be served by the Hub's central energy
plant, expanding the district's shared energy footprint. A part of the Eco-District
development will involve studying the costs and benefits of this configuration . The
success of the district will determine how it could be implemented in the future for A vista's
customers.
Bonneville Power Administration
For many years, Avista received power from the Bonneville Power Administration (BPA)
through a long-term contract as part of the settlement from WNP-3. Most of the BPA's
power is sold to preference customers or in the short-term market. Avista does not have
access to power held for preference customers but engages BPA on the short-term
market. Avista has two other options for procuring BPA power. The first is using the New
Resource NR rate. BPA's power tariff outlines a process for utilities to acquire power from
BPA using this rate for one year at a time. Since this offering is short-term and variable,
Avista does not consider it a viable long-term option for planning purposes, however, it is
a viable alternative for short-run capacity needs. The other option to acquire power from
BPA is to solicit an offer. BPA is willing to provide prices for periods of time when it
believes it has excess power or capacity. This process would likely parallel an RFP
process for future capacity needs and likely take place after current agreements with
public power customers end in 2027.
Existing Resources Owned by Others
Avista has purchased long-term energy and capacity from regional utilities in the past,
specifically the Public Utility Districts in the Mid-Columbia region and has a tolling
agreement for the Lancaster Generating Station. Avista contracts are discussed in
Chapter 3, but extensions or new agreements could be signed. If utilities are long on
capacity, it is possible to develop agreements to strengthen Avista's capacity position.
Since these potential agreements are based on existing assets, prices are dependent on
future markets and may not be cost based. Avista could acquire or contract for energy
Avista Corp 2023 Electric IRP 6-19
Chapter 6: Supply-Side Resource Options
and capacity of other existing facilities without long-term agreements. Avista anticipates
these resources will be offered into future RFPs and may replace any selected resources.
Renewable and Synthetic Natural Gas
Avista did not model the option to use renewable natural gas (RNG) or synthetic natural
gas for electric generation. 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 for use as a fuel in natural gas-fired turbines due to higher end-use efficiency
in customers' homes. Avista's Natural Gas IRP also includes synthetic natural gas as a
resource option , in this case hydrogen is paired with a carbon molecule to create
methane. This methane could be used within the natural gas system and supply gas to
existing generation. This resource is not included due to the similarity to the ammonia
option, but at a higher cost.
Thermal Resource Upgrade Options
Avista investigated opportunities to add capacity at existing facilities for the last several
IRPs, implementing these projects when cost effective. Avista is modeling two potential
options at Rathdrum CT.
Rathdrum CT 2055 Uprates
By upgrading certain combustion and turbine components, the firing temperature can
increase to 2,055 degrees from 2,020 degrees providing a 5 MW increase in output.
Rathdrum CT Inlet Evaporation
Installing a new inlet evaporation system could increase the Rathdrum CT capacity by 10
MW on a peak summer day, but no additional energy is expected during winter months.
Variable Energy Resource Integration Cost
Intermittent energy resources (VER) such as wind and solar require other resources to
help balance the variable energy supply. This results in a cost required by shifting from
otherwise more efficient operations. This is challenging for Avista because the cost could
be the difference of running stored water hours later compared to now. Avista began
studying these costs on its system in 2007. This analysis created the methodology the
Avista Decision Support System (ADSS) model now uses to not only study the costs of
the intermittent resources, but also better equip its real-time operations team with
information to use in managing when to dispatch resources. In this analysis, wind adds
$18 .30 per kW-year and Solar $4.6 per kW-year using the previous IRP's methodology.
Avista is updating its VER integration costs with the assistance of Energy Strategies.11
To minimize cost and utilize ADSS, this is an iterative process between Energy Strategies
11 https://www.energystrat.com/
Avista Corp 2023 Electric IRP 6-20
Chapter 6: Supply-Side Resource Options
and Avista. Energy Strategies has completed base case assumptions for all portfolio
mixes ranging from all wind to a mix of wind/solar to all solar. Currently, Avista is using
ADSS to model sensitivities for the 400 MW wind case to address the next 10 plus years
from the 2021 IRP's Preferred Resource Strategy with low/base/high hydro and
low/base/high market prices. Results are anticipated to be complete by the end of March
2023. By the end of the second quarter in 2023, Energy Strategies will complete the
integration study deliverables including finalizing the calculation of integration costs,
presentation and report of full analysis and results and providing Avista with a tool to
calculate reserves for future scenarios and mixes of VERs.
Sub Hourly Resource and Ancillary Services Benefits
Many of the resources discussed in this chapter may provide reliability benefits to the
electrical system beyond traditional energy and capacity due to intra hour needs and
system reliability requirements. Some resources can provide reserve products such as
frequency response or contingency reserves. Avista is required to hold generating
reserves of 3 percent of load and 3 percent of on-line generation. This means resources
need to be able to respond within 10 minutes in the event of other resource outages on
the system. Within the reserve requirement, 30 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
analysis.
Many types of resources can help with these requirements, specifically storage projects,
natural gas-fired peakers and hydro generation. Some DR options may help in the future
as well. The benefits these projects bring to the system greatly depend on many external
factors including other "capacity" resources within the system, the amount of variation of
both load and generation, market prices, market organization (i .e., EIM), and hydro
conditions. Internal factors also play a role, such as the ability for the resource to respond
in speed and quantity. Avista conducted a study on its Turner Energy Storage project
along with the Pacific Northwest National Lab to understand the operating restrictions of
the technology. For example, if the battery is quickly discharged, the efficiency lowers
and depending on the current state of charge the efficiency is also affected. These
nuances make it more difficult to model in existing software systems.
Avista will continue studying the benefits of energy storage by modeling additional
scenarios including price, water year, and level of renewable penetration. It will also need
to study the benefits of using a sub-hourly model rather than using variability estimates
within the hour. Avista is refining the ADSS model to provide this complete analysis,
although Avista does not expect more detailed analysis to change the current results of
these studies. Avista presented results from two studies regarding the potential analysis
with the ADSS system. These analyses were completed using existing markets and
showed the potential to provide benefits from new resources with flexibility. As Avista
enters a future with additional on-system renewables and an EIM, these estimates will
Avista Corp 2023 Electric IRP 6-21
Chapter 6: Supply-Side Resource Options
need to be revised. Table 6.11 outlines the assumed values for Ancillary Service or within
hour benefits for new construction projects. These estimates also apply to DERs if they
can respond to utility signals.
Table 6.11: Ancillary Services and Sub-hourly Value Estimates (2023 dollars)
Resource $/kW-yr.
Combustion turbine/reciprocatinq enqine 1.00
Lithium-ion battery 4.74
Lithium-ion battery connected to solar 4.58
Pumped hydro 4.74
Flow battery 1.74
Liquid Air 0.50
Qualifying Capacity Credit
As discussed in Chapter 4, Avista is participating in the first non-binding period of the
Western Resource Adequacy Program (WRAP). One purpose of the WRAP is to develop
QCC values for regional resources. For storage hydro resources, a customized
methodology was used to determine the QCC considering 10 years of each resource's
actual historic output (2011 -2020), water in storage, reservoir levels, and both power
and non-power constraints. For run of river resources, an effective load carrying capability
(ELCC) analysis of historical data was performed which resulted in a monthly ELCC for
each resource. An ELCC analysis of historical data was performed and monthly ELCC
were developed by zone. VER zones were defined based on climate and fuel supply, not
transmission . Thermal QCC methodology used unforced capacity (UCAP) analysis of
historical data and incorporated six years of historical data removing the worst performing
year) for each season.
Table 6.12: New Resource QCC Values
Resource January August
(percent) (percent)
Northwest solar 3 24
Northwest wind 8 18
Montana wind 28 13
Off-shore wind 16 36
Storage 4-hour duration 83 83
Storaqe 8-, 16-, or 100-hour duration 98 98
Solar + Storage 25 100
Avista expects the WRAP will lower QCC values over time as more variable energy
resources and storage are added to the system. While it intends to do so, the WRAP has
yet to conduct this analysis. However, there are studies in the public domain estimating
changes in ELCC over time. Avista relies on a regional resource adequacy study12 for
12 Resource Adequacy in the Pacific Northwest, March 2019.
Avista Corp 2023 Electric IRP 6-22
Chapter 6: Supply-Side Resource Options
this assumption investigating high renewable and energy storage penetrations. The
resulting QCC forecast assumed in this IRP for VER and energy storage is shown in
Figure 6.4. These values were determined by using the amount of regional resources
from the wholesale price forecast described in Chapter 8 to the applicable ELCC forecast
value from the regional study.
Figure 6.4: QCC Forecast for VER and Energy Storage
100%
90% -Wind
80% -Solar
"O ~ u 70% -6hr Storage
~ 60% u 12hr Storage C'O 0.. 50% C'O u
Ol 40% C ~
C'O 30%
::::i a 20%
10%
0%
Other Environmental Considerations
All generating resources have an associated greenhouse gas emissions profile, either
when it produces energy, during operations, when constructed, retired, or all the above.
For this analysis, Avista modeled associated emissions with the production of energy as
well as emissions associated with the manufacturing and construction of the facility where
emissions information was available, such as from the NREL data for greenhouse gas
emissions related to construction and operations.
This analysis includes upstream greenhouse gas emissions from natural gas. Natural gas
directly emits 119 pounds of equivalent greenhouse gases per dekatherm when including
the other gases within the supply mix. In addition to those emissions, there could be
upstream emissions from the drilling process and the transportation of the fuel to the plant
also known as fugitive emissions. While not required by the final CETA rules, this analysis
includes these emissions for the Washington customer portion of resource optimization.
The combusted upstream natural gas is estimated to be 0.77 percent13 assuming a
Canadian sourced natural gas supply. The remaining percentage is derived from
estimated methane releases using a 34-year conversion factor from methane to CO2e.
This adjustment results in a 9.8 percent emissions adder to cover upstream methane
leakage and combusted natural gas in the supply.
13 The emission rate is from recent environmental impact studies for the PSE Tacoma LNG plant, Kalama
Manufacturing and Export Facility.
Avista Corp 2023 Electric IRP 6-23
Chapter 6: Supply-Side Resource Options
Social Cost of Greenhouse Gas
The social cost of greenhouse gas (SCGHG) is included for thermal resource project
additions along with projected emissions reduction from energy efficiency for
Washington 's load obligations. The SCGHG is shown in Figure 6.5. Avista uses the
pricing method and the 2.5 percent discount rate identified by the Washington
Commission for CET A. The prices are inflated from 2007 to 2022 using the Bureau of
Economic Analysis inflation data and then inflated at 2.25 percent each year thereafter.
Due to a greenhouse price being included in resource dispatch decisions the within the
wholesale electric price forecast, the values used in the resource optimization model are
reduced by this amount (shown as "Net SCGHG w/GHG Pricing"). The net nominal price
used in the study is also shown in Figure 6.5.
PRiSM, Avista's portfolio optimization model, uses the SCGHG as a cost adder to
Washington's share of greenhouse emitting resources for both existing and new resource
options and the associated regional emission reductions from energy efficiency. Any
emissions associated with operations and construction are also included in the social cost
of greenhouse gas analysis. Avista does not use the social cost of greenhouse gas pricing
for market transactions. After review of Section 14 of the CETA, focusing on these costs
shall be included for evaluating energy efficiency programs and evaluating intermediate
term and long-term resource options in resource plans. Given this section of the law, it
excludes short term transactions.
Figure 6.5: Social Cost of Greenhouse Gas
$250
-SCGHG (2007$)
-scGHG (2022$)
-Nominal$
$200 Net SCGHG w/ GHG Pricing
C: ~ $150
CJ
'i: -a,
~ $100 I,,. a,
Q.
~
$50
$0
Avista Corp 2023 Electric IRP 6-24
Chapter 6: Supply-Side Resource Options
Other Environmental Considerations
There are other environmental factors involved when siting and operating power plants.
Avista considers these costs in the siting process. For example, new hydro projects or
modifications to existing facilities must be made in accordance with their operating
license. If new or upgraded facilities require operations outside this license, the license
would be reopened. When siting solar and wind facilities, developers must solicit and
receive approvals from local, state, and federal governing boards or agencies to ensure
all laws and regulations are met.
If Avista sites a new natural gas-fired facility, it will have to meet all state and local air
requirements for its air permit. Requirements are at levels these governing bodies find
appropriate for their communities. Currently, Avista is not evaluating emissions costs
outside of these considerations.
Non-Energy Im pacts
Washington's CETA requires investor-owned utilities to consider equity-related non­
energy impacts (NEis) in integrated resource planning. To accomplish this, Avista
contracted with DNV to perform a NEI study on supply-side resources with a goal to 1)
conduct a jurisdictional scan to identify additional NEis that were not specifically listed in
Avista's scope, 2) identify NEis available through federal and regulatory publications, 3)
develop quantitative estimates on a $/MWh or $/kW basis as appropriate for each
resource, and 4) conduct a gap analysis to provide recommendations to prioritize future
research based on the necessary level of effort or anticipated value.
A supply-side NEI database and a final report was completed on April 8, 2022.
Accordingly, Avista includes NEis within the resource strategy analysis for the supply­
side resources modeled. This is in addition to the NEis that had previously been included
on energy efficiency. These impacts include the societal impacts of Avista's decision
making of Avista's resources and represent quantifiable values to prioritize resource
choices. By including these impacts, the analysis can prioritize resource decisions
equitably. For example, resources with air emissions versus those without are properly
evaluated to consider the environmental impact on local communities. The NEI values
used for this analysis are in Table 6.13. Where Avista did not have a value from DNV it
estimated its value by using approximation techniques.
There were areas where there was insufficient information for DNV to provide estimated
NEI values for any specific NEI types for specific supply-side resources. For many of
these areas, the research value and effort to address these gaps were significant.
Examples of some of these with insufficient information were related to public health,
safety, reliability and resiliency, energy security, environmental (wildfire, land use, water
use, wildlife, surface air effects), economic, and decommissioning relative to some or all
resource types (e.g., battery storage, hydrogen electrolyzer, etc.). Washington directives
indicate a movement to require NEis in resource planning and research to quantify these
would require significant time and investment, it seems a more cost-effective consistent
approach would be best conducted at a state-wide level. DNV's Supply Side Non-Energy
Avista Corp 2023 Electric IRP 6-25
Chapter 6: Supply-Side Resource Options
Impacts report covering the values, assumptions and the gap analysis is included in
Appendix D.
Table 6.13: IRP Resource NEI Values
Resource Operating Construction
Impact Impact
($/MWh) ($/kW)
Solar 0.41 44.8
Wind 0.83 89.6
Natural Gas -2.86 59
Storaqe 0 44.27
Wood Biomass -7.54 102.8
Small Modular Nuclear Reactor 1 102.8
Pumped Hydro 8.22 458
Hydrogen Fuel Cell 0.28 59
Avista Corp 2023 Electric IRP 6-26
Chapter 7: Transmission & Distribution Planning
7. Transmission & Distribution Planning
This chapter introduces the Avista Transmission and Distribution (T&D) systems and
provides a brief description of how Avista studies these systems and recommends capital
investments to maintain reliability while accommodating future growth. Avista's
Transmission System is only one part of the networked Western Interconnection with
specific regional planning requirements and regulations . This chapter summarizes
planned transmission projects and generation interconnection requests currently under
study and provides links to documents describing these studies in more detail. This
section also describes how distribution planning is incorporated into the IRP and Avista's
merchant transmissions system rights.
Section Highlights
• Avista actively participates in regional transmission planning forums.
• Avista develops annual transmission and distribution system plans.
• Transmission Planning estimates costs of locating new generation on the Avista
system for the I RP.
• Avista formed a Distribution Planning Advisory Group (DPAG) for additional
stakeholder involvement, education, and transparency.
• Increasing electrical infrastructure to electrify both building and transportation in
the Washington State service area is estimated to cost an additional 4 cents per
kWh.
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 7.1 ).
Figure 7.1: Avista Transmission System
Sandpoint
rk Fork
Noxon
~ Thompson Falls
Avista Corp 2023 Electric IRP 7-1
Chapter 7: Transmission & Distribution Planning
230 kV Transmission System
The backbone of the Avista Transmission System operates at 230 kV. Figure 7.2 shows
a station-level drawing of Avista 's 230 kV Transmission System including network
interconnections to neighboring utilities. Avista's 230 kV Transmission System is
interconnected to Bonneville Power Administration's (BPA) 500 kV transmission system
at the Bell, Hatwai, and Hot Springs substations.
In addition to providing enhanced transmission system reliability, network
interconnections serve as points of receipt for power from generating facilities outside
Avista's service area. These interconnections provide for the interchange of power with
entities within and outside the Pacific Northwest, including integration of long-and short­
term contract resources.
Avista Corp
Figure 7.2: Avista 230 kV Transmission System
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2023 Electric IRP
ubnet Gor(}a Swyd. AVA
7-2
Chapter 7: Transmission & Distribution Planning
Transmission Planning Requirements and Processes
Avista coordinates transmission planning activities with neighboring interconnected
transmission owners. Avista complies with Federal Energy Regulatory Commission
(FERC) requirements related to both regional and local area transmission planning. This
section describes several of the processes and forums important to A vista's transmission
planning.
Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) is responsible for promoting bulk
electric system reliability, compliance monitoring and enforcement in the Western
Interconnection. This group facilitates the development of reliability standards and
coordinates interconnected system operation and planning among its membership.
WECC is the largest geographic territory of the regional entities with delegated authority
from the National Electric Reliability Council (NERC) and the 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 7.3 for the map of NERC Interconnections including
WECC.
RC West
California Independent System Operator's (ISO) Reliability Coordinator (RC) West
performs the federally mandated reliability coordination 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 7.3: NERC Interconnection Map
Western Interconnection /
/
......
' ' ERCOT '
Interconnection' ,
stern
Interconnection
■MRO ■NPCC ORF ■SERC □Texas RE ■WECC
1 https://www.wecc.biz/Paqes/About.aspx.
Avista Corp 2023 Electric IRP 7-3
Chapter 7: Transmission & Distribution Planning
Western Power Pool
Avista is a member of the Western Power Pool (WPP), an organization formed in 1942
when the federal government directed utilities to coordinate river and hydro operations to
support war-time production. The WPP 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. WPP membership is voluntary and
includes the major generating utilities serving the Northwestern U.S., British Columbia,
and Alberta. The WPP operates several committees, including its Operating Committee,
the Reserve Sharing Group Committee, the Western Frequency Response Sharing
Group Committee, the Pacific Northwest Coordination Agreement (PNCA) Coordinating
Group and the Transmission Planning Committee (TPC).
NorthernGrid
NorthernGrid formed on January 1, 2020. Its membership includes fourteen utility
organizations within the Northwest and many external stakeholders. NorthernGrid aims
to enhance and improve the operational efficiency, reliability, and planned expansion of
the Pacific Northwest transmission grid. Consistent with FERG requirements issued in
Orders 890 and 1000, NorthernGrid provides an open and transparent process to develop
sub-regional transmission plans, assess transmission alternatives (including non-wires
alternatives) and provide a decision-making forum and cost-allocation methodology for
new transmission projects. NorthernGrid is a new regional planning organization created
by combining the members of ColumbiaGrid and the Northern Tier Transmission Group.
System Planning Assessment
Development of Avista's annual System Planning Assessment (Planning Assessment)
encompasses the following processes:
• Avista Local Transmission Planning Process -as provided in Attachment K, Part
Ill of Avista's Open Access Transmission Tariff (OATT);
• NorthernGrid transmission planning process -as provided in the NorthernGrid
Planning Agreement; and
• 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
Avista Corp 2023 Electric IRP 7-4
Chapter 7: Transmission & Distribution Planning
work is in the Transmission Planning folder on Avista's OASIS site. Avista's System
Planning Assessment is posted on OASIS. Avista's most recent transmission planning
document highlights several areas for additional transmission expansion work including:
■ Big Bend -Transmission system capacity and performance will significantly
improve upon completion of the new Othello Substation and Othello Switching
Station 115 kV Transmission Line. These projects are the last phase of the Saddle
Mountain 230 kV system reinforcement adding a fourth source into the load center.
The addition of communication aided protection schemes and other reconductor
projects will improve reliability and lessen the impacts of system faults. This project
is needed for continued load growth in the area and integration of utility scale
renewable generation.
■ Coeur d'Alene -The completion of the Coeur d'Alene -Pine Creek 115 kV
Transmission Line rebuild project and Cabinet -Bronx -Sand Creek 115 kV
Transmission Line rebuild project will improve transmission system performance
in northern Idaho. The addition and expansion of distribution substations and a
reinforced 115 kV transmission system are needed in the near-term planning
horizon to support load growth and ensure reliable operations in this area.
■ Lewiston/Clarkston -Load growth in the Lewiston/Clarkson area contribute to
heavily loaded distribution facilities. Additional performance issues have been
identified that are relating to the ability for bulk power transfer on the 230 kV
transmission system. A system reinforcement project is under development to
accommodate the load growth in this area.
■ Palouse -Completion of the Moscow 230 kV station rebuild project added capacity
and mitigated several performance issues. The remaining issue is a potential
outage of both the Moscow and Shawnee 230/115 kV transformers. An operational
and strategic long-term plan is under development to best address a possible
double transformer outage in this area.
■ Spokane -Several performance issues exist with the present state of the
transmission system in the Spokane area and are expected to worsen with
additional load growth. The Westside 230 kV station capacity increase and Sunset
Substation rebuild are near completion. The completed Irvin 115 kV switching
station adds much needed reliability and flexibility to the Spokane Valley. The
staged construction of new facilities to support load growth at the Garden Springs
230 kV station is under development. Dependency on the 230 kV Beacon station
leaves the system susceptible to performance issues for outages related to
transmission lines terminating at the station.
Generation Interconnection
An essential part of the IRP is estimating transmission costs to integrate new generation
resources onto Avista's transmission system. A summary of proposed IRP generation
options along with a list of Large Generation Interconnection Requests (LGIR) are
Avista Corp 2023 Electric IRP 7-5
Chapter 7: Transmission & Distribution Planning
discussed in the following sections. The proposed LGIR projects have independent
detailed studies and associated cost estimates and are listed below for reference.
IRP Generation Interconnection Options and Estimates
IRP Generation Interconnection Options (Table 7.1) shows the projects and cost
information for each of the !RP-related studies where Avista evaluated new generation
options. These studies provide a high-level view of generation interconnection costs and
are similar to third-party feasibility studies performed under Avista's generator
interconnection process. In the case of third-party generation interconnections, FERC
policy requires a sharing of costs between the interconnecting transmission system and
the interconnecting generator. Accordingly, Avista anticipates all identified generation
integration transmission costs will not be directly attributable to a new interconnected
generator.
Table 7.1: 2023 IRP Generation Study Transmission Costs
100/200 230kV
100 230kV
Bend area near Odessa 200/300 230kV
Bend area near Othello 100/200 230kV
Bend area near Othello 300 230kV
Bend area near Reardan 50 115kV 9.7
Bend area near Reardan 100 115kV 10.3
Clarkston/Lewiston area 100/200/300 230kV 1.9
Kettle Falls substation, existin POI 12/50 115kV 1.8
Kettle Falls substation, existin POI 100 115kV 24.9
Lower Granite area 100/200/300 230kV 2.9
Northeast substation, existin POI 10 115kV 1.6
Northeast substation, existin POI 100 115kV 6.7
Palouse area, near Benewah Tekoa 100/200 230kV 2.4
Rathdrum substation, existin POI 25/50 115kV 11.5
Rathdrum substation, existin POI 100 230kV 16.7
Rathdrum substation, existin POI 200 230kV 27.0
Rathdrum Prairie, north Greensfer Rd 100 230kV 32.7
Rathdrum Prairie, north Greensfer Rd 200 230kV 43.0
Rathdrum Prairie, north Greensferr Rd 300 230kV 54.4
Rathdrum Prairie, north Greensferr Rd 400 230kV 91 .5
Thornton substation, existin POI 10/50 230kV 1.9
West Plains area north of Airwa Hei hts 100 230kV 2.4
hts 200/300 230kV 4.7
2 Cost estimates are in 2022 dollars and use engineering judgment with a 50 percent margin for error.
Avista Corp 2023 Electric IRP 7-6
Chapter 7: Transmission & Distribution Planning
Large Generation Interconnection Requests
Third-party generation companies may request transmission studies to understand the
cost and timelines required for integrating potential new generation projects. These
requests follow a strict FERG process to estimate the feasibility, system impact and facility
requirement costs for project integration. After this process is completed, a contract offer
to integrate the interconnection project may occur and negotiations can begin to enter
into a transmission agreement, if necessary. Table 7.2 lists information associated with
potential third-party resource additions currently in Avista's interconnection queue. 3
Table 7.2: Third-Party Large Generation Interconnection Requests
Serial or Former Size Cluster Queue (MW) Type County State
Number Number
Senior 46 126 Wind Adams WA
Senior 52 100 Solar Adams WA
Senior 60 150 Solar Asotin WA
Senior 66 71 Wood Burner/ CT Stevens WA
Senior 59 116 Solar/Storaqe Adams WA
Senior 63 26 Hydro Kootenai ID
Senior 79 2.1 Solar Spokane WA
Senior 80 19 Solar Spokane WA
Senior 84 5 Solar Stevens WA
Senior 97 100 Solar/Storaqe Nez Perce ID
TCS-02 62 123 Wind Adams WA
TCS-03 67 80 Solar/Storaqe Adams WA
TCS-04 73 94 Solar/Storaqe Adams WA
TCS-05 76 114 Solar Grant WA
TCS-06 81 94 Solar/Storaqe Adams WA
TCS-07 85 5 Solar Adams WA
TCS-08 99 200 Solar/Storaqe Franklin WA
TCS-09 100 100 Solar/Storaqe Spokane WA
TCS-10 103 40 Solar Lincoln WA
TCS-11 104 120 Wind Spokane WA
TCS-12 105 5 Solar Stevens WA
TCS-14 110 375 Wind/Solar/Storaqe Garfield WA
TCS-16 112 125 Solar/Storaqe Lincoln WA
TCS-18 119 200 Solar/Storaqe Grant WA
3 https://www.oasis.oati.com/woa/docs/A VAT/
Avista Corp 2023 Electric IRP 7-7
Chapter 7: Transmission & Distribution Planning
Distribution Resource Planning
Avista continually evaluates its distribution system for reliability, level of service, and
future capacity. The distribution system consists of approximately 350 feeders covering
30,000 square miles, ranging in length from three to 73 miles. Avista serves 410,000
electric customers on its grid.
Avista has taken several steps since the 2021 IRP to include resource benefits in the
studies performed to ensure the adequacy of the distribution system. Some steps are a
result of ongoing planning improvements, and others are prescribed in Washington's
CETA.
Beyond resource planning or the day-to-day business of keeping the system functional,
the future of the distribution system is dynamic in terms of needs. Electric transportation,
all-electric buildings, behind the meter generation and storage, and data centers are
examples of modern disruptions to the distribution system. Understanding these
applications and predicting the system impacts is challenging. To do so requires more
data, more tools, and more people. Avista has hired two new distribution planning
engineers to help in these efforts.
Avista developed several tools to assist in understanding how the system is currently
used, how it may be used in the future, and building models for analysis. The tools
forecast long-and short-term demand, and weather adjusted demand, using common
automated statistical methods. These tools are useful but may require future
enhancements. At some point, Avista may need to source additional tools from the
industry with vetted and acceptable results across several utilities.
In the State of Washington, Avista has completed its implementation of an advance
metering infrastructure (AMI), giving the utility a rich data source for analysis. Consuming
the amount of data and understanding it is a challenge. Early returns indicate a future
without AMI would be challenging given policy directions for resource planning. The data
gives visibility to the entire distribution system. At any given moment the performance of
every distribution element is being measured, including trunks, secondary trunks, and
laterals. Without AMI these systems were rarely measured. The data is also correlated to
time. Time series analysis is essential when anticipating future resource and mitigation
opportunities.
As part of CETA, Avista has started the Distribution Planning Advisory Group (DPAG).
Avista's website has been updated to include a landing page for the DPAG and provide
opportunities for interested parties to join the advisory group. The intention of the group
is to gain feedback from interested parties about distribution planning and the associated
inputs and outputs of planning.
In 2022, Avista and a consultant formulated a process change for non-wire alternatives
and distributed energy resources (DERs) to be considered for grid mitigation. Non­
traditional mitigation alternatives were shown to require new steps in the development
and eventual operation of a project. The process covers the spectrum from planning, to
Avista Corp 2023 Electric IRP 7-8
Chapter 7: Transmission & Distribution Planning
operations, to stakeholder engagement.4 This work is being incorporated into the existing
planning process. The development of a DER potential assessment (currently under
contract) will help determine the availability of non-traditional mitigation alternatives for
specific geo-graphic areas.
Deferred Distribution Capital Investment Considerations
New technologies such as energy storage, photovoltaics, and demand response
programs may help the electric system by deferring or eliminating future capital
investments in distribution and transmission . This benefit depends on the new
technologies' ability 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, energy storage may help meet
overall peak load needs or provide voltage support on the distribution feeder or at the
distribution substation.
The analysis for determining the capital investment deferment value for DERs is not the
same for all locations on the system. Feeders differ by whether they are summer-or
winter-peaking, the time of day when peaks occur, capacity thresholds, and the rate of
local load growth. It is not practical to have a deferment estimate for each feeder in an
IRP, but it is prudent to have a representative estimate included in the IRP resource
selection analysis.
To fairly evaluate and select the most cost-effective solutions to mitigate system
deficiencies, the planning process needs to identify the deficiency well in advance of it
becoming a performance issue. Longer evaluation periods provide for a comprehensive
evaluation so the solution can take a holistic approach to include system resource needs.
A shorter period can lead to immediate action that does not lend itself to a stacked value
analysis due to time constraints for acquiring and/or constructing a non-wire alternative.
Identifying future deficiencies in a timely matter has become a focus of System Planning.
As previously mentioned, spatial forecasting, load data, time-series analysis, and
accurate modeling are critical to making decisions as early as possible. For the 2023-
2024 system assessment Avista will use tools and data previously unavailable in the last
assessment. The additional clarity will facilitate the evaluation of DER's as mitigation
options for any deficiencies identified.
At this time, Distribution Planning has not identified any projects meeting the criteria for
an economic non-wire alternative. The near-term distribution projects require capacity
increases and duration requirements exceeding reasonable DER capacity.
4 Modern Grid Solutions® Work Product
Avista Corp 2023 Electric IRP 7-9
Chapter 7: Transmission & Distribution Planning
Reliability Impact of Distributed Energy Storage
Utility-scale batteries may offer benefits to grid operations. Reliability is one benefit often
associated with batteries. This is particularly true in situations where the battery system
is commissioned as a mitigation solution on the distribution system.
There is an industry trend to broaden the list of remedies available to alleviate grid
deficiencies beyond traditional wires-based solutions. The solutions are typically called
non-wire alternatives, but it may be more informative to call them non-traditional
alternatives. The motivation behind the trend is reasonable as non-traditional approaches
may be less expensive than legacy options and may also incorporate other ancillary
benefits, such as in the case of batteries. Utilities should consider all viable options to
arrive at a least cost and reliable solution to distribution issues. In addition to solving grid
issues, some non-wire alternatives may also serve as a system resource. These
alternatives are referred to as DERs. Batteries, the subject of this section, are one such
non-wire alternative with other benefits.
It is often presumed batteries increase system reliability. This may be true in some
applications, but in the narrow sense of non-wire alternatives, this would typically not be
the case. In the simplest of terms, reliability can decrease with the addition of a battery
because the battery and its control system are additional failure points in the existing
system chain. It is difficult to identify a case where this reduction in reliability from the
added potential failure points is not true.
A common issue on the distribution grid is feeder capacity constraints. A constrained
feeder typically approaches the operational constraint during the daily peak load. The
historical mitigation for this type of constraint is to increase the capacity of the constraining
element by installing a larger conductor, different regulators, a larger transformer, or
building a new substation. With the advent of utility-scale batteries, utilities have another
option to mitigate these types of feeder constraints. Employing battery storage can
effectively shift load from the daytime, when limited and expensive resources are the
norm, to the nighttime, when more abundant and less expensive resources may be
available.
When DE Rs are used to solve a constraint in this manner, the battery, or other generating
resource, is added to existing distribution facilities. It does not replace existing facilities,
and this is a key point as the probability of failure of the existing facilities remains. The
probability of failure of the battery or other non-wire alternative system is now an
additional failure point. This is analogous to a feeder as a chain where each link is a
potential failure point. If the chain consists of 100 links, there are 100 points of possible
failure along the entire chain. In the same manner, adding a battery to a feeder to mitigate
an issue simply adds another link, and another possible fa ilure point, in the chain. Instead
of 100 possible points of failure, there are now 101 possible points of failure. Granted
there are temporal aspects to this as well, but the battery will not always be required
solution to fix a constraint. If a failure occurs in the battery when there is no constraint,
the feeder can continue operating as normal with no adverse impacts to the system. But
there will be times when the battery is needed to meet a local peak event and during
those times the battery becomes an additional failure point with the expanded system.
Avista Corp 2023 Electric IRP 7-10
Chapter 7: Transmission & Distribution Planning
The annual net effect on the feeder is potentially reduced reliability especially as the
reliability of current battery technology is less than other traditional solutions.
The shift in reliability is more significant if a traditional solution was chosen. Existing older
links in the failure chain would be replaced with new, often more robust, and more reliable,
links. To take the chain analogy even further, if a new substation is built, links are removed
from the failure chain as each affected feeder becomes shorter and has less
environmental exposure. In addition, there is increased resiliency due to added
operational flexibility and the ability to serve load from different directions. The net effect
of a traditional solution is increased reliability, and it facilitates future DER resource
additions because traditional solutions allow the grid to more readily accept additional
DERs.
Quantifying the real effect of a grid-fixing battery or similar resource on reliability is difficult
and situational. Indeed, it may not rise to a level of concern given the temporal nature of
the decrease in reliability. The benefit of the resource may outweigh the short period of
time it increases failure probability. However, if the failure probability increases
significantly, an alternate solution may be warranted. From an IRP perspective, the notion
of solving a distribution grid deficiency while simultaneously providing a system resource
is intriguing and worthy of consideration, but system reliability improvements cannot be
assumed .
Electrification Impact Analysis
Avista's distribution system is not designed for a high penetration of electrification of
existing customer's transportation and space/water heating loads. Many studies including
this IRP and past IRP's concentrate on the power supply and transmission requirements
of these new loads, but do not estimate distribution system costs. Traditionally,
distribution planning is outside the scope of an IRP as the IRP focuses on the generation
of the power supply not the delivery, but the cost to change the distribution system is
informational to understand the full impacts of a major transition policy decision for
Avista's customers.
This IRP contemplates four electrification scenarios for plausible Washington State load
changes within IRP planning horizon (discussed in Chapter 10). The scenarios use
alternative forecasts for higher electric vehicle (EV) adoption and a transition to using
electric space and water heat of existing customers. Additional load requirements by
existing customers will have an impact of the distribution system since the system was
not designed for the additional load. The system changes and costs to integrate new
loads will be a time-consuming exercise requiring assumptions for the impacts of each
individual customer for each of the scenarios. To shorten the requirements for such a
study, Avista chose to estimate the system impacts for the highest load forecast scenario
and base its estimate on high level assumptions for system requirements based on known
costs to construct system components. This analysis gives an approximate estimate to
add to power and transmission cost estimates traditionally estimated in a resource plan.
There are two options to increase distribution capacity, one is to increase voltage of the
system; this option requires replacing all distribution underground cable, line insulation,
substation power transformers, voltage regulators, and numerous other equipment. The
Avista Corp 2023 Electric IRP 7-11
Chapter 7: Transmission & Distribution Planning
second option is using the same distribution voltage to split the existing system up into
additional feeders by adding additional substations along with replacing targeted
conductors. Both options will require replacement of service transformers and conductors
from the transformer to the home. For this analysis the second option is used to estimate
the system costs .
Avista then estimated the required replacement components based on the judgement of
Avista's planning engineers and construction personnel. The high electrification scenario
adds 1,225 MW of additional winter peak load by 2045, but for system planning purposes
this is increased to 1,450 MW to account for higher loads due to the power supply
planning metric based on a 1 in 2 weather event and the distribution system must plan
for lower temperature events at 1 in 10 year lowest daily temperature. With the amount
of new load known, the number of new feeders is estimated by assuming a new feeder
can service 10 MW of new load. Then using an estimate of a new feeder substation can
service four feeders is the basis for estimating the associated system components to
service the new load without requiring a detailed study. Table 7.3 summarizes the total
system cost estimates, these estimates include the required distribution system
reconductoring , new transmission connections, and customer transformer and
connection points. The total cost in 2023 dollars is $1 .9 billion dollars or $57 million per
feeder substation, when adjusting for inflation timing, the cost rises to $3.3 billion in total
capital cost through 2045 (the current book value of the Washington distribution assets is
approximately $1 billion as a comparison, Avista already adds approximately two feeders
per year for load growth).
With this cost per substation forecast, a cash flow can be estimated based on spreading
the required work between 2028 and 2045 and adjusting for inflating capital costs using
a cost per feeder substation. Avista also estimates additional support employees will be
required to facilitate the load growth. Avista estimates this to be an increase of 46 full time
employees for support roles by 2045.
The combined new support labor force and capital investments using a 50-year life
amortization results in a 2045 revenue requirement to Washington customers at $378
million. When dividing by 9,520 GWh of retail sales, the average rate is an additional 4
cents per kWh (the expected PRS average kWh rate is 23 cents per kWh in 2045).
Although the incremental cost per additional kWh sales is 14.5 cents per kWh.
Avista Corp 2023 Electric IRP 7-12
Chapter 7: Transmission & Distribution Planning
Table 7.3: T&D Requirements for the Combined Electrification Scenario
(2023$ Millions)
Item Units Unit Cost Total Cost
New Feeder Substations 36 Stations $15.0 $542
Reconductor Distribution 163 Miles $0.5 $81
115kV Transmission (Substation lnteqration) 72 Miles $4.0 $289
Switchinq Station (230kV/115kV) 6 Stations $75.0 $450
230kV Transmission (Switchinq Station lnteqration) 30 Miles $2.3 $68
Service Transformers 32,000 $10k $320
Reconductor Service Connections 1,910 miles $62k $118
Total Cost $1,868
Cost per Feeder Substation $57
Merchant Transmission Rights
Avista has two types of transmission rights. The first rights include Avista's owned
transmission . This transmission is reserved and purchased by Avista's merchant
department to serve Avista customers. Avista-owned transmission is also available to
other utilities or power producers. FERC separates utility functions between merchant
and transmission functions to ensure fair access to Avista's transmission system. The
merchant department dispatches and controls the power generation for Avista and
purchases transmission from the Avista transmission operator to ensure energy can be
delivered to customers. Avista must show a load serving need to reserve transmission on
the Avista-owned transmission system to ensure equitable access to the transmission
capacity. Appendix E shows the projected need and future use of the Avista transmission
system.
Avista also purchases transmission rights from other utilities to serve customers (see
Table 7.3). This transmission is procured on behalf of the merchant side of Avista. The
merchant group has transmission rights with BPA, Portland General Electric (PGE), and
a few smaller local electric utilities.
Table 7.4: Merchant Transmission Rights
6/30/2026
8/1/2026
BPA 8/1/2026
BPA 8/1/2026
BPA 125 10/31/2027
BPA 50 07/30/2026
BPA Townsend to Garrison 210 9/30/2027
PGE 100 12/31/2028
Northern Li hts As needed n/a
Kootenai Electric As needed 12/31/2028
Avista Corp 2023 Electric IRP 7-13
Chapter 7: Transmission & Distribution Planning
This Page is Intentionally Left Blank
Avista Corp 2023 Electric IRP 7-14
Chapter 8: Market Analysis
8. Market Analysis
A fundamental energy market analysis is an important consideration to support the
Avista's resource strategy over the next 20 plus years. Avista uses forecasts of future
market conditions of the Western Interconnect to optimize its resource portfolio options.
Electric price forecasts are used to evaluate the net operating margin of each supply-and
demand-side resources, including distributed energy resources (DER) options, 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.
Section Highlights
• Solar and wind dominate future generation across the West while natural gas
and increasing amounts of storage will ensure resource adequacy as existing
coal and natural gas plants retired or reduce dispatch.
• By 2045, this study assumes 94 percent of generation in the Pacific Northwest
will be carbon free, up from approximately 70-80% today depending on hydro
conditions.
• Greenhouse gas emissions (GHG) will fall to historic lows with the expansion
of renewables and continued coal and natural gas plant retirements. By 2045,
expected emissions will be 62% less than in 1990.
• The 22-year wholesale electric price forecast (2024-2045) is $35.34 per MWh.
Expansion of renewables reduces future mid-day prices, but evening and
nighttime prices will be at a premium compared to today's pricing.
• Natural gas prices continue to remain low; for example, the levelized price at
Stanfield (2024-2045) is $3.98 per dekatherm.
Avista conducts its wholesale market analysis using the Aurora model by Energy
Exemplar. The model includes generation resources, load estimates and transmission
links within the Western Interconnect. This chapter outlines the modeling assumptions
and methodologies for this Integrated Resource Plan (IRP) and includes Aurora's primary
function of electric market pricing (Mid-Columbia for Avista), as well as operating results
from the analysis. The Expected Case is the average of 300 simulations of future
outcomes using the best available information on policies, regulations, and resource
costs.
Electric Marketplace
Avista simulates the entire Western Interconnect electric system for its IRP planning;
shown as Western Electricity Coordinating Council (WECC)1 in Figure 8.1. The rest of the
U.S. and Canada are in separate electrical systems. The Western Interconnect includes
1 WECC is the Western Electrical Coordinating Council. It coordinates reliability for the Western
Interconnect.
Avista Corp 2023 Electric IRP 8-1
Chapter 8: Market Analysis
the U.S. system west of the Rocky Mountains plus two Canadian provinces and the
northwest corner of Mexico's Baja peninsula.
The Aurora market simulation model represents each operating hour between 2024 and
2045. It simulates both load and generation dispatch for sixteen regional areas or zones
within the west. Avista's load and most of its generation is in the Northwest zone identified
in Table 8.1 . Each of these zones include connections to other zones via transmission
paths or links. These links allow generation trading between zones and reflect operational
constraints of the underlying system, but do not model the physics of the system as a
power flow model. Avista focuses on the economic modeling capabilities of the Aurora
platform to understand resource dispatch and market pricing effects resulting in a
wholesale electric market price forecast for the Northwest zone or Mid-Columbia
marketplace.
Avista Corp
Figure 8.1: NERC Interconnection Map
NERCINTERCONNECTIONS
if __ J
J '
WECC
'-_...._-I -------
INTERCONNECTION ., ' ...,
,,, " TRE ', ....
/ ' ....
WESTERN ,, ., ~ ' ,
ERCOT '.
INTERCONNECTION
Table 8.1: AURORA Zones
Northwest-OR/WA/ID/MT Southern Idaho
Utah Wyominq
EASTERN
INTERCONNECTION
Eastern Montana Southern California
Northern California Arizona
Central California New Mexico
Colorado Alberta
British Columbia South Nevada
North Nevada Baja Mexico
2023 Electric IRP 8-2
Chapter 8: Market Analysis
The Aurora model estimates its electric prices using an hourly dispatch algorithm to match
the load in each zone with the available generating resources. Resources are selected to
dispatch considering fuel availability, fuel cost, operations and maintenance cost,
dispatch incentives/disincentives, and operating constraints. The marginal cost of the last
generating resource needed to meet area load becomes the electric price. The IRP uses
these prices to value each resource (both supply and load side) option and select
resources to achieve a least reasonable cost plan meeting all load and reliability
obligations. Avista also conducts stochastic analyses for its price forecasting, where
certain assumptions are drawn from 300 distributions of potential inputs. For example,
each forecast randomly draws from an equally weighted probability distribution of the 30-
year rolling hydro record .
The next several sections of this chapter discuss the assumptions used to derive the
wholesale electric price forecast, resulting dispatch and greenhouse gas emissions
profiles of the west for the 300 stochastic studies.
Western Interconnect Loads
Each of the sixteen zones in Aurora require hourly load data for all 22 years of the forecast
plus 300 different stochastic studies for weather variation. Future loads may not resemble
past loads from an hourly shape point of view due to the continual increase in electric
vehicles (EVs) and rooftop solar. Changes in energy efficiency, demand curtailment/
demand response, varying state policies, population migration, and economic activity
increase the complexity. While each of these drivers are important to the power pricing
forecast, it takes a large amount of analytical time to estimate or track these macro effects
over the region. Avista uses the following methods to derive its regional load forecast for
power price modeling to account for these complexities.
Avista begins with Energy Exemplar's demand forecast included with the Aurora software
package. This forecast includes an hourly load shape for each region along with annual
changes to both peak and energy values. Avista updates the load forecast using a
national consultant's expectations on future loads. Figure 8.2 shows this base forecast as
the black dashed line. The WECC load grows 0.95 percent per year. Avista adjusts this
initial forecast to account for changes in EV penetration and net-metered generation,
including rooftop solar. Annual EV load grows at 14.0 percent and net-metered generation
grows at 5.3 percent.2 These adjustments increase the load forecast growth rate to
approximately 1.4 percent per year. Within the year, the hourly load shapes adjust to
reflect charging patterns of both residential and commercial vehicles in addition to most
net-metered generation being modeled as fixed roof mount solar panels.
2 Avista uses forecasts provided by a national consulting firm to assist in the development of these
forecasts.
Avista Corp 2023 Electric IRP 8-3
Chapter 8: Market Analysis
Figure 8.2: 22-Year Annual Average Western Interconnect Load Forecast
160,000
150,000
140,000
130,000
"' = (tl 120,000 3: (tl
C, 110,000 a,
:E
a, 100,000 C,
(tl ... a, 90,000 ~
80,000
70,000
60,000
--Base Load Forecast
-Base Load w/ NetMeter Generation
-Net Load Forecast
-Base Load w/ PHEV Load
~ ~ ~ ~ ~ ~ 0 ~ N M ~ ~ ~ ~ ~ ~ 0 ~ N M ~ ~ N N N N N N M M M M M M M M M M ~ ~ ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
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. The load forecast increases 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 Federal
Energy Regulatory Commission (FERC) Form 714 load data from 2015 to 2019 as
presented in the 2021 IRP. To maintain consistent west coast weather patterns,
statistically significant correlation factors between the Northwest and other Western
Interconnect load areas represent how electricity demand changes together across the
system. This method avoids oversimplifying Western Interconnect loads. Absent the use
of correlations, stochastic models may offset changes in one variable with changes in
another, virtually eliminating the possibility of broader load excursions witnessed by the
electricity grid. The additional accuracy from modeling loads this way is crucial for
understanding wholesale electricity market price variation as well as the value of peaking
resources and use in meeting system variation.
Avista Corp 2023 Electric IRP 8-4
Chapter 8: Market Analysis
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 components:
• Resources currently available or known upgrades;
• Resources retiring or converting to a new fuel source;
• New resources for capacity and load service;
• New resources for renewable energy compliance;
• Transmission/distribution additions; and
• Fuel prices, fuel availability and operating availability.
Aurora contains a database of existing generating resources with the location, size and
estimated operating characteristics for each resource. When a resource has a publicly
scheduled retirement date or is part of an approved provincial phase-out plan, it is retired
for modeling purposes on the expected date. Avista does not project retirements beyond
those with publicly stated retirement dates or phase out plans. Plants becoming less
economic in the forecast dispatch fewer hours. Several coal plant retirements have or are
expected to occur in the Northwest during this IRP, including Boardman, Colstrip Units 1
and 2, North Valmy, and Centralia. Figure 8.3 shows the total retirements included in the
electric price forecast. Approximately 21,000 MW of coal, 15,000 MW of natural gas,
3,600 MW of nuclear,3 and 827 MW of other Western Interconnect resources including
biomass, hydro and geothermal are known to be retiring by the end of 2045.
Figure 8.3: Cumulative Resource Retirement Forecast
45,000
■ Coal ■ Natural Gas ■ Nuclear Hydro ■ Other
40,000
35,000
30,000
CJ) = 25,000 ~ 3:: ~ 20,000 Cl <II :E: 15,000
10,000
5,000
0
3 Avista will re-assess the Diablo Canyon closure assumption in the 2025 IRP.
Avista Corp 2023 Electric IRP 8-5
Chapter 8: Market Analysis
New Resource Additions
To meet future load growth, considering state clean energy goals and replacement of
retired generation, a new generation forecast must include enough resources to meet
peak load. Furthermore, some states include emission constraints or require emission
pricing for new resource additions. Avista uses a resource adequacy-based forecast for
new resource additions along with data estimates provided by a third-party consultant.
The process begins with a forecast of new generation by resource type from a nationally
based third-party consultant. Consultants with multiple clients and dedicated staff can,
more efficiently than Avista, research new resource costs and operating characteristics
on likely resource construction in the West, especially in areas where Avista has no
market presence or local market knowledge. These forecasts for new generation account
for environmental policies and localized cost analysis of resource choices to develop a
practical new resource forecast.
The next step in this process adjusts the clean energy additions to reflect changes in state
policies for additional renewable energy requirements to ensure the new renewable
resource build out matches requirements given the load forecast for each region. The last
step runs the model for 300 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 285 of the 300 iterations, a 95
percent loss-of-load threshold measuring reliability.
Figure 8.4 shows the 370 GW of added generation included in this forecast. The added
resources include 116 GW of utility-scale solar, 71 GW of wind, 22 GW of natural gas
combined cycle combustion turbines (CTs), 94 MW of storage,4 36 GW of natural gas
CTs and 31 GW of other resources including hydro, biomass, geothermal, and net­
metering.
4 Storage energy to capacity ratio averages 3 hours in 2024 and increases to 6 hours by 2045. This change
assumes technological advances in the duration of batteries and other storage technologies.
Avista Corp 2023 Electric IRP 8-6
Chapter 8: Market Analysis
Figure 8.4: Western Generation Resource Additions (Nameplate Capacity)
350
300
250
VJ 200 i: (II
== (II
Cl 0 150
100
50
0 2025 2030 2035 2040 2045
■NH3CT 0.0 0.0 00 00 0.0
■H2CT 0.0 0.5 1.4 1.7 2.4
■OSWind 0.0 0.0 1.5 7.1 13.7
CCCT 3.8 6.2 6.2 7.9 10.0
SCCT 3.6 8.9 11.1 11 .8 12.8
■DR 1.5 2.1 2.3 2.5 2.8
■Storage 5.2 18.3 37.0 48.7 58.1
Net-Meter 4.5 7.6 9.5 11.1 12.8
■Solar 19.0 59.4 85.8 111 .5 125.4
■Wind 11 .9 39.8 54.2 67.5 83.2
■ Geothermal 0.7 2.5 4.1 6.2 8.9
■Biomass 0.1 0.3 0.5 0.7 0.8
■ Hydro 1.3 1.5 1.8 2.1 2.5
Generation Operating Characteristics
Several changes are made to the resources available to serve future loads to account for
Avista's specific expectations, such as fuel prices, and to reflect potential variation of
resource supply such as wind and hydro generation.
Natural Gas Prices
Historically, natural gas prices were the greatest indicator of electric market price
forecasts. Between 2003 and 2021 the correlation (R2) between natural gas and on-peak
Mid-Columbia electric prices was 0.81 , indicating a strong but recently decreasing
correlation between the two prices than has been historically observed. Natural gas-fired
generation facilities were typically the marginal resource in the northwest except for times
when hydro generation was high due to water flow. In addition, natural gas-fired
generation met 34 percent of the load in the U.S. Western Interconnect in 2021 . With the
large increases in new solar and wind generation in the west, the number of hours where
natural gas-fired facilities will set the marginal market price is expected to decline.
Avista Corp 2023 Electric IRP 8-7
Chapter 8: Market Analysis
For modeling purposes, Avista uses a baseline of monthly natural gas prices and varying
prices based on a distribution for each of the 300 stochastic forecasts. The forecasts
begin with the Henry Hub forecast. Since Avista is not equipped with fundamental
forecasting tools, nor is it able to track natural gas market dynamics across North America
and the world, it uses a blend of market forward prices, consultant forecasts, and the
Energy Information Administration (EIA) forecast. The EIA forecast is compared below in
Figure 8.5 against forecasted Henry Hub prices from two consultants with the capability
to follow the fundamental supply and demand changes of the industry. The 22-year
nominal levelized price of natural gas is $4.49 per dekatherm. 5
E ...
(I.I .s::: -(ti
.!II: (I.I
0 ...
(I.I a.
ti)
Figure 8.5: Henry Hub Natural Gas Price Forecast
$8.00 ~---------------------------~
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
= IRP Forecast
-Consultant 1
-NYMEX
-consultant 2
-EIAIAEO
_/4-
-----
~ ~ ~ ~ ~ ~ 0 ~ N M ~ ~ ~ ~ ~ ~ 0 -N M ~ ~ N N N N N N M M M M M M M M M M ~ V ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Natural gas generation facilities in the West do not use Henry Hub as a fuel source, but
natural gas contracts are priced based on the Henry Hub index using a basin differential.
Northwest basins include Sumas for coastal plants on the Northwest pipe system. Power
plants on the GTN pipeline obtain fuel at prices based on AECO , Stanfield, or Malin
depending on contracted delivery rights. Table 8.2 shows these basin differentials as a
percent change from Henry Hub for the deterministic case. This table also includes basin
nominal levelized prices for 22 years for the selected basins.
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 300 iterations. The methodology to change prices uses an autocorrelation algorithm
allowing prices to experience excursions, but to not move randomly. The methodology
works by focusing on the monthly change in prices. The forecast's month-to-month
Expected Case change in prices is used as the mean of a lognormal distribution; then for
the stochastic studies, a monthly change in natural gas price is drawn from the
5 The natural gas pricing data is available on the IRP website within Appendix F.
Avista Corp 2023 Electric IRP 8-8
Chapter 8: Market Analysis
distribution. The lognormal distribution shape and variability uses historical monthly
volatility. Using the lognormal distribution allows for the large upper price excursions seen
in the historical dataset.
Table 8.2: Natural Gas Price Basin Differentials from Henry Hub
Year Stanfield Malin Sumas AECO Rockies Southern
CA
2024 93.4% 97.0% 95.6% 87.8% 100.3% 100.9%
2025 88.0% 95.9% 90.4% 81.2% 99.0% 101 .5%
2030 88.8% 95.4% 91 .2% 76.4% 105.3% 102.2%
2035 89.9% 96.7% 93.0% 78.6% 108.2% 104.1%
2040 87.6% 93.5% 91 .0% 78.3% 102.1% 100.7%
2045 85.5% 89.6% 89.7% 79.1% 97.1% 97.7%
22 vr. $3.98 $4.27 $3.74 $3.55 $3.99 $4.20
The average of the 300 stochastic prices is similar to the expected price forecast
described earlier in this chapter. Figure 8.6 illustrates the simulated data for the stochastic
studies compared to the input data for the Stanfield price hub. The stochastically derived
nominal levelized price for 22 years is $3.98 per dekatherm. These values likely would
converge with a sample size much larger than 300. The median price is lower at $3.91
per dekatherm. Another component of the stochastic nature of the forecast is the growth
in variability. In the first year, prices vary 9 percent around the mean, or the standard
deviation as a percent of the mean. By 2040, this value is 40 percent, and holds close to
40 percent through 2045. Avista uses higher variation in later years because the accuracy
and knowledge of future natural gas prices becomes less certain.
Figure 8.6: Stochastic Stanfield Natural Gas Price Forecast
$10.00
$9.00
$8.00
E $7.00 ...
Cl) ..c: ....
Ill ~ Cl)
C
$6.00
$5.00
ai $4.00 a.
~ $3.00
$2.00
$1.00
$0.00
Avista Corp
□Average
25th Percentile
-50th Percentile
• 95th Percentile
• Deterministic Input
.A
V ~ W ~ ~ m O ~ N M V ~ W ~ ~ m O ~ N M V ~ N N N N N N M M M M M M M M M M V V V V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
2023 Electric IRP 8-9
Chapter 8: Market Analysis
Figure 8. 7 shows another way to visualize A vista's natural gas price forecast
assumptions. This chart shows the 22-year nominal levelized prices for Stanfield as a
histogram to demonstrate the skewness of the natural gas price forecast.
Figure 8.7: Stanfield Nominal 20-Year Nominal Levelized Price Distribution
30%
t 25%
s::::
('Cl
1-B 20%
(J
0
0 15%
~
ii 10%
('Cl .c 0
a:.. 5%
0%
0 l,l')
0 N N N V. V.
Regional Coal Prices
0.00
0 l,l') 0 l,l') 0 l,l') ,..._ 0 N l,l')
N N M M C"i V. V. V. V. V.
0.02
□=
l,l') 0 l,l') 0 l,l') 0 l,l') 0 l,l') ,..._ 0 N l,l') ,..._ 0 N l,l') ,..._
M -.i -.i -.i -.i I.I") I.I") I.I") I.I")
V. V. V. V. V. V. V. V. V.
Coal-fired generation facilities are still an important part of the Western Interconnect. In
2021 , coal met 17 percent of WECC loads, falling from 34 percent in 2001. Coal pricing
is typically different from natural gas pricing , providing diversification thus mitigating price
volatility risk. Natural gas is delivered by pipeline, whereas coal delivery is by rail , truck,
or conveyor. Coal contracts are typically longer term and supplier specific. Avista uses
the coal price forecast provided by the software vendor's default database. The software's
forecast is based on FERC filings for each of the coal plants and is used to determine
historical pricing . Future prices are based on the EIA Annual Energy Outlook.
Coal price forecasts have uncertainty like natural gas prices, yet the effect on market
prices is less because coal-fired generation rarely sets marginal prices in the Western
Interconnect. While labor, steel, and transportation costs drive some portion of coal price
uncertainty, transportation is its primary driver. There is also uncertainty in fuel suppliers
as the coal industry is restructuring. Given the relatively small effect on Western
Interconnect market prices , Avista chose not to model this input stochastically.
Hydro
The Northwest U.S., British Columbia, and California have substantial hydro generation
capacity. Hydro resources were 55 percent of Northwest generation in 2021 , although
hydro generation is only 19 percent of generation in the Western Interconnect. A favorable
characteristic of hydro power is its ability to provide near-instantaneous generation up to
and potentially beyond its nameplate rating. Hydro generation is valuable for meeting
Avista Corp 2023 Electric IRP 8-10
Chapter 8: Market Analysis
peak load, following general intra-day load trends, storing and shaping energy for sale
during higher-valued hours and integrating variable generation resources. The key
drawback to hydro generation is its variability and limited fuel supply.
The deterministic forecast uses a rolling 30-year median of hydro production including a
combination of historic water years and forecasted generation incorporating the
temperature change predictions in Representative Concentration Pathway (RCP) 4.5. 6
As you move through the 22-year planning horizon, there is a greater percentage of
forecasted generation included in the 30-year period. For example, for planning year
2030, hydro is based on a median of historic water years from 2000-2021 and forecasted
hydro for years 2022-2029. See Figure 8.8 for a hydro comparison of this methodology
with the former average of 80-year hydro.
Figure 8.8: Northwest Hydro Generation Comparison
20,000 -----------------------------~
18,000
16,000
~ 14,000
"' ~ 12,000
Cl a, :E 10,000
a, Cl e s.ooo
a,
~ 6,000
4,000
2,000
OCT NOV DEC JAN
-1929-2008 -1992-2021 -2023-2045
FEB MAR APR MAY JUN JUL AUG SEP
Many forecasts use an average of the hydro record, whereas the stochastic study
randomly draw from the record , as the historical distribution of hydro generation is not
normally distributed. Avista uses both methodologies. Avista's stochastic forecast
incorporates the same combination of the historic water years and forecasted hydro as
used in the deterministic study, however, hydro is randomly selected for the 300 iterations
to simulate risk of different hydro conditions. Figure 8.9 shows the average hydro energy
as 13,213 aMW (median 13,411 aMW) in the Northwest over the 22-year study, defined
here as Washington, Oregon, Idaho, and western Montana. The chart also shows the
range in potential energy used in the stochastic study, with a 10th percentile water year of
11 ,290 aMW (-15%) and a 90th percentile water year of 14,728 aMW (+11 %).
6 See Chapter 7 for more detail on the hydro forecast and climate assumptions included.
Avista Corp 2023 Electric IRP 8-11
Chapter 8: Market Analysis
Figure 8.9: Northwest Expected Energy
25%
20%
~ 15%
.a
(ll .a 0 Cl. 10%
S% --■~111 0%
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ll) o_ ll)_ o _ ll)_ o _ ll) o _ ll)_ o _ ll) m 0 0 ..-..-N N (") (") 'SI" 'SI" ..-..-..-..-..-..-..-
Average Megawatts
Wind Variation and Pricing
I 2% ■.2l.--0%
0 0 0 0 0 0 0 0 0 0 0 0 o_ ll)_ o _ ll) o_ ll)
ll) ll) <D <D r---r---..-..-..-..-..-..-
Wind is a growing generation source used to meet customer load. Western Interconnect
wind generation increased from nearly zero in 2001 to 12 percent in 2021 .7 Capturing the
variation of wind generation on an hourly basis is important in fundamental power supply
models due to the volatility of its generation profile and the effect of this volatility on other
generation resources and electric market prices. Energy Exemplar recently made
significant progress populating a larger database of historical wind data points throughout
North America. This analysis leverages this work and takes it one step further by including
a stochastic component to change the wind shape for each year. Avista uses the same
methodology for developing its wind variation as discussed in previous IRPs. The
technique includes an auto correlation algorithm with a focus on hourly generation
changes. It also reflects the seasonal variation of generation.
To keep the problem manageable, Avista developed 15 different annual hourly wind
generation shapes that are randomly drawn for each year of the 22-year forecast. By
capturing volatility this way, the model can properly estimate hours with oversupply
compared with using monthly average generation factors.
Solar
Like wind, solar is increasing its market share in the Western Interconnect. In 2021 solar
was 4 percent8 of the total generation, up from 2 percent in 2014 (both estimates exclude
behind the meter solar). The Aurora model includes multiple solar generation shapes with
multiple configurations, including fixed and single-axis technologies, along with multiple
locations within an area. As solar continues to grow, additional data will be available and
7 Wind represented 11.6 percent of Northwest generation in 2021 .
8 Solar represented 1 percent of Northwest generation in 2021.
Avista Corp 2023 Electric IRP 8-12
Chapter 8: Market Analysis
incorporated into future IRP modeling. One of these new techniques may include multiple
hourly solar shapes like those used with wind, so the model can account for solar variation
from cloud cover.
Other Generation Operating Characteristics
Avista uses the Energy Exemplar database assumptions for all other generation types
not detailed here, except for Avista owned and controlled resources. For Avista's
resources, more detailed confidential information is used to populate the model.
Forced outage and mechanical failure is a common problem for all generation resources.
Typically, the modeling for these events is through de-rating generation. This means the
available output is reduced to reflect the outages. Avista uses this method for solar, wind,
hydro, and small thermal plants; but uses a randomized outage technique for larger
thermal plants where the model randomly causes an outage for a plant based on its
historical outage rate, keeping the plant offline for its historical mean time to repair.
Negative Pricing and Oversupply
Avista includes adjustments in the Aurora model to account for oversupply in the Mid­
Columbia market, including negative price effects. Negative pricing occurs when
generation exceeds load. This occurs most often in the Northwest when much of the hydro
system is running at maximum capacity in the spring months due to high runoff and wind
projects are also generating and lacking an economic incentive to shut off due to their
requirement to generate for the Production Tax Credit (PTC), environmental attributes
(e.g., Renewable Energy Credits (RECs)) or sale obligations. While hydro resources are
dispatchable, they may not be able to dispatch off due to constraints of total dissolved
gas forcing spill instead of generating. This phenomenon will likely increase as wind and
solar generation is added to the system where there are tax credits in place or where
environmental attributes are needed for clean energy requirements. To model this effect
in Aurora, Avista changes the economic dispatch prices for several resources that have
dispatch drivers beyond fuel costs.
The first change Avista made is to the hydro dispatch order. This makes hydro resources
a "must run" resource or last resource to turn off. To do this, hydro generation is assigned
a negative $30 per MWh price (2020 dollars).9 The next change assigns an $8 per MWh
(2020$) reduction in cost for qualifying renewable resources to reflect a preference for
meeting state renewable portfolio standards (RPS); this price adjustment accounts for the
intrinsic value of the REC. The last adjustment is to include a PTC for resources with this
benefit. After these adjustments, the model turns off resources in a fashion similar to
periods of excess generation seen today. In an oversupply condition such as this , the last
resource turned off sets the marginal price.
9 These plants cannot be designated with a "must run" designation due to the "must run" resources requiring
resources to dispatch at minimum generation and for modeling purposes, hydro minimum generation is
zero in the event of low flows.
Avista Corp 2023 Electric IRP 8-13
Chapter 8: Market Analysis
Greenhouse Gas Pricing
Many states and provinces have enacted GHG emissions reduction programs with others
considering such programs. Some states have emissions trading mechanisms while
others chose clean energy targets. Aurora can model either policy, but different policy
choices can result in dissimilar impacts to electric wholesale pricing. Clean energy target
programs, such as Washington's Clean Energy Transformation Act (CETA), generally
depress prices due to the bias for increasing the incentives to construct low marginal­
priced resources. California's cap and trade program has the opposite effect and pushes
wholesale prices upwards. Avista includes known pricing programs in California, British
Columbia, and Alberta in its modeling as a carbon tax. The modeling also includes effects
of Washington's Climate Commitment Act (CCA) and Oregon's Clean Energy Targets
(HB 2021).
The Washington State Legislature passed the CCA in 2021 enacting the potential for
carbon pricing on Washington generation resources beginning in 2023.10 Final CCA rules
were released only this past October 2022 and all regulated entities are still striving to
comprehend its complete impacts. The regulatory entity responsible for enacting the law
is the Washington State Department of Ecology (Ecology). Ecology has not yet provided
detailed descriptions or examples to aid regulated entities such as Avista in calculating
compliance costs and it is unclear how this legislation will impact energy markets.
Therefore, carbon pricing continues to be extremely uncertain and modeling
methodologies will be updated in a future resource plan once the full requirements are
known. In the meantime, the prices included in the analysis are shown in Figure 8.10 and
the methodology used for these assumptions11 is described below.
1) Utility controlled generation within Washington state -No GHG prices are
included within the dispatch decision since allowances will be no-cost for generation
controlled by Washington utilities serving Washington customers and trued up at the
end of the compliance period .
2) Non-utility owned generation within Washington state -This pricing is a blend of
the Vivid Economics price scenario where Washington joins the California market in
2025 and the Revised 2019 Integrated Energy Policy Report (IEPR) Carbon Price
Projections. Specifically, the Vivid Economics price is used through 2024, the average
of IEPR's low-and mid-prices are used between 2025 and 2029, and beginning in
2030, the price trends down to IEPR's low price by 2032.12 This is labeled as the
"California Linked CCA" price in Figure 8.10.
3) Utility controlled generation within Washington state serving other states -
applies the pricing used from #2 above using the ratio of the utility's out of state load
share.
4) Northwest Imports-Any power imported into the Northwest uses the pricing from #2
above based on the greenhouse gas intensity rate of the exporting region.
10 Pricing relative to other emission sources was also enacted but irrelevant to this IRP.
11 Various approaches were discussed with the TAC at multiple meetings and through email. Input and/or
enhancements to this process were sought and included based on the best available information at the
time of the analysis.
12 These prices were presented as "Scenario 2" to the IRP TAC.
Avista Corp 2023 Electric IRP 8-14
Chapter 8: Market Analysis
5) National Carbon Price -assumes the 33% probability of the U.S adopting a national
carbon tax or national cap-and-trade in 2030 of $12 per metric ton increasing to $62
per metric ton by 2045. Washington facilities assume this cost within its dispatch, but
facilities in California do not. These prices are referenced as "National Policy" in Figure
8.10.
... (l)
Q.
~
$120
$100
$80
$60
$40
$20
$0
(") ..,.
N N 0 0 N N
Figure 8.10: Carbon Price Comparison
-California
-California Linked CCA
-National Policy
LO t0 ,.._ 00 a, 0 .... N (") ..,. LO t0 ,.._ 00 N N N N N (") (") (") (") (") (") (") (") (")
0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N
a, 0 .... N (") ..,.
(") ..,. ..,. ..,. ..,. ..,.
0 0 0 0 0 0 N N N N N N
This forecast assumes a continuing shift to clean energy resources across the Western
Interconnect over the next 22 years. Figure 8.11 shows the historical and forecast
generation for the U.S. portion of the Western lnterconnect.13 In 2022, 52 percent of load
is served by clean energy, increasing to 73 percent by 2030, and 81 percent by 2045. To
achieve this shift in energy, while also serving new loads, solar and wind production will
displace coal and natural gas. Absent significant new storage technologies, thermal
resources are still required to help meet system needs during peak weather events,
especially in Northwest winters.
The Northwest will undergo significant changes in future generation resources. 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 2022, 76 percent of the Northwest generation was clean , increasing to 88 percent in
2030 and 94 percent by 2045 as shown in Figure 8.12. Achieving these ambitious clean
energy goals will require more than doubling of wind generation and a nearly 12-fold
increase in solar energy from the 2021 generation levels. This results in solar providing
11 percent of future generation and wind 24 percent.
13 Forecast is for the average of the 300 simulations.
Avista Corp 2023 Electric IRP 8-15
120,000
100,000
en ....... ....... 80,000 ro ~ ro CJ)
Q) ~ 60,000
Q)
CJ) ro I...
Q) 40,000 > <(
20,000
30,000
25,000
2 1u 20,000
~ ro
CJ)
Q)
~ 15,000
Q)
CJ) ro j 10.000
5,000
Chapter 8: Market Analysis
Figure 8.11: WECC Generation Technology History and Forecast
Other ■ Hydro Nuclear ■ Coal ■ Wind ■ Solar Natural Gas
-NMv~m~oomo-NMV~w~oomo-NMV~w~oomo-NMv~w~oomo-NMV~ 000000000----------NNNNNNNNNNMMMMMMMMMMVVVVVV 000000000000000000000000000000000000000000000 NNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNNN
Figure 8.12: Northwest Generation Technology History and Forecast
Other ■ Hydro Nuclear ■ Coal ■ Wind ■ Solar Natural Gas ■ Petroleum
r ---r
I I I 11 I I I I 11
,I
Regional Greenhouse Gas Emissions
GHG emissions are likely to significantly decrease with the retirement of coal generation
and new solar/wind resources displacing additional natural gas-fired generation. Electric
generation related GHG emissions within the U.S. Western Interconnect were
Avista Corp 2023 Electric IRP 8-16
Chapter 8: Market Analysis
approximately 214 million metric tons in 2020, a considerable reduction from the 1990
emissions level of 234 million metric tons. Avista obtained historical data back to 1980
from the EPA; the emissions minimum since 1980 was 161 million metric tons in 1983.
Avista's market modeling only tracks emissions at their source and does not estimate
assignment to each state from energy transfers, such as emissions generated in Utah for
serving customers in California. Figure 8.13 shows the percent totals for 2020 and the
2045 forecast. The largest emitters by state are Arizona and California, followed by
Colorado, Utah, and Wyoming. The four northwest states generate 14 percent of the total
emissions in the Western Interconnect.
By 2045, Avista estimates emissions fall 37 percent compared to 1990 levels as shown
in Figure 8.14. All states will have a reduction in emissions in this forecast. The greatest
reductions by percentage are Utah (89 percent), New Mexico (83 percent), Montana (77
percent) and Nevada (74 percent). The greatest reductions by tons are Utah (26 MMT),
Wyoming (25 MMT), California (24 MMT), and New Mexico (22 MMT).
Figure 8.13: 2020 and 2045 Greenhouse Gas Emissions
50.0
45 .0 ■2020 2045
1/) 40.0 C
.Q
1/) 35 .0 .!!1
E 30 .0 w
co 25.0 ... 0 r 20.0 -0 ... 15.0 C
G> (.) 10.0 ....
G> 0.. 5.0
AZ CA co UT WY NM MT NV WA OR ID
Avista Corp 2023 Electric IRP 8-17
Chapter 8: Market Analysis
Figure 8.14: Greenhouse Gas Emissions Forecast
350
-AZ -cA -co
300 ID -MT -NV
NM OR UT
250 -wA -WY -1990
II)
C 200 0 I-
u ·;:: 150 -Cl)
:i:
C 100 0
~ 50
Regional Greenhouse Gas Emissions Intensity
To understand the GHG emissions from the regional market Avista may purchase power
within, Avista uses regional emissions intensity per MWh to estimate the associated
emissions from these short-term acquisitions. Avista uses the mean values shown in
Figure 8.15 for each of the 300 simulations. Figure 8.15 below shows the mean, 25th and
75th percentiles for regional emissions intensity. The emissions are included from
Washington, Oregon, Idaho, Montana, Utah, and Wyoming. Emissions intensity falls as
renewables are added and coal plants and natural gas retire or decrease dispatch, but
the intensity rate depends on the variation in hydro production. The locations for Avista's
area for potential market purchases is consistent with Washington's energy and
emissions intensity report but is higher than Avista's likely counter parties for market
purchases. This figure also includes incremental regional emissions to evaluate efficiency
programs. In this case, Avista determines the incremental regional emission per MWh
using a second forecast with additional load within the northwest system, then the change
in emissions is compared to the change in load.
Avista Corp 2023 Electric IRP 8-18
Chapter 8: Market Analysis
.c: 3: ~ ...
Q) a.
en .0
Figure 8.15: Northwest Regional Greenhouse Gas Emissions Intensity
600
500
400
300
200
100
0
• Mean .t. 75th Percentile ■ 25th Percentile
■ • ■ • ■ • • ■ ■ • • • • • • ■ ■ • ■ ■ ■
■ • ■
V ~ ~ ~ ~ m O ~ N M V ~ ~ ~ ~ m O ~ N M V ~ N N N N N N M M M M M M M M M M V V V V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Electric Market Price Forecast
Mid-Columbia Price Forecast
There are two wholesale prices forecasts within this resource plan, a deterministic version
where all 8,760 hours for the 22-year period are simulated and a stochastic version
simulating 300 of the 22-year hourly studies. Each study uses hourly time steps between
2024 and 2045. This process is time consuming when conducted 300 times for the
stochastic forecast. The 300 future simulations take more than one week of continuous
processing on 33 separate processor cores to complete. Time constraints limited the
number of market scenarios Avista is ultimately able to explore in each resource plan. In
prior IRPs, Avista's stochastic studies included 500 iterations of hourly time steps,
however, the increase in future storage resources within the marketplace requires
optimization techniques to determine pricing. This process significantly increases the
modeling time such requiring the number of iterations to be reduced. Analysis was
performed to ensure the 300 iterations was sufficient to encompass most of the
distribution of uncertainty.
The annual average of all hourly prices from both studies are shown in Figure 8.16. This
chart shows the annual distribution of the prices using the 10th and 95th percentiles
compared to the mean, median and deterministic prices. The pricing distribution is
lognormal as prices continue to be highly correlated with the lognormally distributed
natural gas prices. The 22-year nominal levelized price of the deterministic study is
$35.48 per MWh and $35.44 per MWh for the stochastic study is shown in Table 8.3.
Table 8.4 includes the super peak evening (4 to 10 p.m.) period to illustrate how prices
behave during this high-demand period where solar output is falling, and rising prices
encourage dispatching of other resources.
Avista Corp 2023 Electric IRP 8-19
$70
$60
$50
ai $40
C.
$30
$20
$10
$0
Chapter 8: Market Analysis
Figure 8.16: Mid-Columbia Electric Price Forecast Range
□Average 10th percentile -Median ,. 95th percentile ♦ Deterministic
A A
A
♦
A A
A A A A
A
A A A A A A
A
V ~ ~ ~ ~ ~ 0 ~ N M V ~ ~ ~ ~ N N N N N N M M M M M M M M M 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N
~ ~ ; 0 0 0 N N N
A A
Table 8.3: Nominal Levelized Flat Mid-Columbia Electric Price Forecast
Metric 2024-2045
Levelized
($/MWh)
Deterministic $35.48
Stochastic Mean $35.44
10th Percentile $31 .94
50th Percentile $35.29
95th Percentile $40.84
A A
Average on-peak prices between 7 a.m. and 10 p.m. on weekdays plus Saturday have
historically been higher than the remaining off-peak prices. However, this forecast shows
off-peak prices outpacing on-peak prices on an annual basis beginning in 2029 due to
increasing quantities of solar generation placed on the system depressing on-peak prices.
As more solar is added to the system , this effect spreads into the shoulder months. Only
in the winter season, where solar production is lowest, does the traditional relationship of
today's on-and off-peak pricing continue.
Depending on the future level of storage and its duration, price shapes could flatten out
rather than inverting the daytime spread. Mid-day pricing will be low in all months going
forward, driving on-peak prices lower. Super peak evening prices after 4 p.m., when other
resources will need to dispatch to serve load, can be high if startup costs effect market
pricing as expected in this forecast.
Avista Corp 2023 Electric IRP 8-20
Chapter 8: Market Analysis
Table 8.4: Annual Average Mid-Columbia Electric Prices ($/MWh)
Year Flat Off-Peak On-Peak Super
Peak
Evening
2024 $42.87 $38.56 $46.10 $60.15
2025 $35.87 $32.57 $38.33 $52.29
2026 $33.24 $30.80 $35.07 $49.22
2027 $29.89 $28.65 $30.82 $45.21
2028 $29.83 $29.74 $29.90 $44.89
2029 $29.93 $30.46 $29.52 $44.96
2030 $34.65 $35.97 $33.66 $51.48
2031 $32.57 $33.87 $31.59 $50.24
2032 $31.63 $33.33 $30.36 $48.71
2033 $32.57 $34.44 $31.17 $51 .13
2034 $33.11 $35.14 $31 .58 $51 .97
2035 $34.41 $37.11 $32.40 $53.40
2036 $35.06 $38.03 $32.84 $54.60
2037 $36.67 $38.98 $34.93 $58.60
2038 $36.37 $38.76 $34.58 $59.06
2039 $37.51 $40.50 $35.26 $60.62
2040 $39.50 $42.02 $37.60 $66.68
2041 $39.70 $42.16 $37.85 $67.33
2042 $41.46 $42.99 $40.31 $72.16
2043 $42.40 $43.69 $41.44 $73.97
2044 $47.58 $48.76 $46.70 $81 .89
2045 $47.48 $48.88 $46.42 $81 .17
2024-2045 $35.44 $35.76 $35.20 $54.99
Figures 8.17 through 8.20 show the average prices for each hour of the season for every
five years of the price forecast. The spring and summer prices generally stay flat
throughout the 22 years as these periods have large quantities of hydro and solar
generation to stabilize prices, but mid-day prices decrease over time while prices for the
other time periods increase. The winter and autumn prices will have larger price increases
due to less available solar energy to shift unless enough long-term storage materializes.
With this analysis, current on/off-peak pricing will need to change into different products
such as a morning peak, afternoon peak, mid-day, and night. Pricing for holidays and
weekends likely will be less impactful on pricing except for the morning and evening
peaks. Future pricing for all resources will need to reflect these pricing curves so they can
be properly valued against other resources.
Avista Corp 2023 Electric IRP 8-21
Chapter 8: Market Analysis
Figure 8.17: Winter Average Hourly Electric Prices (December -February)
$250
$200
..c $150 s: ::E ...
Q) a. $100
~
$50
$0
$250
$200
..c $150 s: ::E ...
Q) a. $100
~
$50
$0
Avista Corp
-2025 -2030 2035
-2040 -2045
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
Hour
Figure 8.18: Spring Average Hourly Electric Prices (March -June)
-2025 2030 2035
-2040 -2045
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
Hour
2023 Electric IRP 8-22
Chapter 8: Market Analysis
Figure 8.19: Summer Average Hourly Electric Prices (July -September)
$250
$200
.c $150 ~ :: ...
Q)
0.. $100
~
$50
$0
-2025 -2030 2035
-2040 -2045
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
Hour
Figure 8.20: Autumn Average Hourly Electric Prices (October -November)
$250
$200
.c $150 ~ :: ... (I)
c. $100
~
$50
$0
Avista Corp
-2025 -2030 2035
-2040 -2045
1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12
Hour
2023 Electric IRP 8-23
Chapter 8: Market Analysis
This Page is Intentionally Left Blank
Avista Corp 2023 Electric IRP 8-24
Chapter 9: Preferred Resource Strategy
9. Preferred Resource Strategy
Avista recently negotiated several resource acquisitions from its 2022 All-Source Request
for Proposals (RFP) to meet customer energy and capacity needs into the mid-2030s.
These acquisitions include both renewable resources and existing baseload natural gas
from northwest energy suppliers. While large scale utility resources are meeting
customer's needs, Avista will continue to invest in cost effective energy efficiency (EE)
and other distributed energy resources (DER), pilot demand response (DR) programs,
and invest in energy solutions in Named Communities (highly impacted communities and
vulnerable populations). Avista also announced a plan to transfer out of its ownership of
Colstrip by the end of 2025.
Section Highlights
• The 2022 All-Source RFP resource selections satisfy the customer's load and
capacity forecast through the mid-2030s.
• Energy efficiency's impact on future load growth is slowing due to saturation.
• Named Community Investment Fund (NCIF) will increase distributed energy
resources such as energy efficiency, small-scale renewables, and energy
storage.
• Non-energy impacts are included to evaluate both demand-and supply-side
resource selection for Washington resources.
• Avista needs long-duration storage to serve customers in peak hours after 2035
to achieve 100% clean energy targets.
• Greenhouse gas emissions fall by 80% by 2045 with the Preferred Resource
Strategy (PRS).
• New transmission is needed to achieve Washington's 100% clean energy
goals.
Background
Avista has announced several resource acquisitions and a divestiture since its 2021 IRP.
These changes reflect one of Avista's biggest portfolio transformations since the early
2000s, beginning with the addition of two separate 5% purchases of Chelan PU D's Rocky
Reach and Rock Island facilities from the 2020 Renewable RFP. The 2022 All-Source
RFP then produced a 30-year Wind Purchase Power Agreement (PPA), an upgrade of
the Kettle Falls Biomass Facility, and an extension of the Lancaster CCCT PPA through
2041. Announcements adjacent to the 2022 All-Source RFP include the acquisition of
power from Columbia Basin Hydro's irrigation hydro generation fleet, 30 MW of industrial
demand response, and the divestiture of Avista's 15% share of Colstrip Units 3 & 4 at the
end of 2025. In previous IRPs and the 2021 Clean Energy Implementation Plan (CEIP)
Avista has also indicated an intention to upgrade the Post Falls hydroelectric facility,
currently projected for completion by the end of 2029.
Avista Corp 2023 Electric IRP 9-1
Chapter 9: Preferred Resource Strategy
Figure 9.1 : Announced Resource Changes Since 2021 IRP
Industrial Demand Response
Chelan PUD's Rock Island &
Rocky Reach (#2) i-:::::::=::::::::::=
Columbia Basin Hydro's
Irrigation Generation
Chelan PUD's Rock Island &
Rocky Reach (#3)
Kettle Falls Biomass Upgrade
30-Year Wind PPA
Colstrip 3 & 4
Lancaster CCCT
Post Falls Hydro Upgrade
Resource Strategy Objectives
87.5 MW
283MW
6.4 MW
..,. "' "' "' 0 0 N N
(0,..,_(00) M M M M 0 0 0 0 N N N N
0 ;g ;g 3 3 3 3 N N N N N N
Avista needs reliable sources of power to meet peak planning requirements for both
summer and winter peak loads to control enough energy to meet customers' normal
demand and enough clean generation resources to meet Washington State's goals.
Avista must also maintain system reliability, while meeting the regulatory and legal
obligations of Idaho and Washington , including the Clean Energy Transformation Act's
(CETA) requirement of serving Washington's retail loads with 100% non-emitting
resources by 2045.
The acquisition strategy uses the best information available at the time of these analyses,
including Avista 's interpretation of CETA requirements. CETA rules are still in
development for items such as the "use" rule determining what renewable energy will
qualify as "primary" versus "alternative compliance". The IRP utilizes a least-cost planning
methodology using specific social cost impacts specified by Washington's requirements
for planning and including Non-Energy Impact (NEI) studies for alternative resources
conducted by DNV.1 Due to differing state Idaho and Washington policies, Avista
separates the two jurisdictions for this analysis by creating an individual resource
selection plan for each state and as a system where possible.
Avista's PRS describes the lowest reasonable cost resource mix given Avista's needs for
new capacity, energy, and clean or non-carbon emitting resources for each state, while
accounting for social and economic factors prescribed by state policies. The PRS includes
supply-side resources, and DER options including EE and DR, to serve customer loads.
The plan compares resource options to find the lowest-cost portfolio considering the non­
power costs to meet capacity deficits in the winter and summer, annual energy and clean
energy/CETA requirements. The analysis considers a minimum spending threshold for
1 Available in Appendix D
Avista Corp 2023 Electric IRP 9-2
Chapter 9: Preferred Resource Strategy
using the Named Communities Investment Fund (NCIF)2 monies available to enhance
the equitable transition to clean energy in Named Communities in Avista's Washington
electric service territory.
Resource Selection Process
Avista utilizes a mixed integer optimization model to select supply-and demand-side
resources to meet customer energy and capacity needs. Avista developed Preferred
Resource Strategy Model (PRiSM) to aid in resource selection using information from its
dispatch model, Aurora. PRiSM evaluates each resource option 's capital recovery, fixed
operation costs, and non-energy financial impacts relative to their operating margins from
Aurora and the option's capability to serve energy, peak loads, and clean energy
obligations. PRiSM then determines the lowest-cost mix of resource options meeting
Avista's resource needs. The model can also measure and optimize the risk of various
portfolio additions when informed by Monte Carlo data. For this analysis, Avista includes
its forecast of 300 Monte Carlo market futures rather than a single forecast for its
evaluation. PRiSM is publicly available in Appendix F.
PRiSM
Avista staff developed the first version of PRiSM in 2002 to support resource decision
making in the 2003 IRP. The model continues to support the IRP as enhancements have
improved the model over time. PRiSM uses a mixed integer programming routine to
support complex decision making with multiple objectives. Its results ensure optimal
values for variables given system constraints. The model uses an add-in function to Excel
from Lindo Systems named What's Best along with Gurobi's solver. Excel then becomes
PRiSM's user interface. PRiSM simultaneously solves to meet system reliability, energy
obligations and jurisdictional clean energy standards while minimizing costs.
The model analyzes resource needs by state for the entire Avista system to ensure each
state will be assigned the appropriate amount of incremental costs (if any) of new
resource choices. PRiSM includes state-level load and resource balances by month , must
be added to satisfy deficits for each state and the system in calendar year segments. The
model can also retire existing resources when they become uneconomic. 3
2 The NCIF was proposed in Avista's 2021 CEIP and commits to spend up to $5 million annually on specific
actions in Named Communities.
3 Resources can only be retired at the system level. PRiSM is not set up to "retire" a resource from serving
only one state and transferring the output to the other state. Avista's PRS analysis "turns off' this feature
and does not include additional model selected retirements beyond those discussed in this chapter.
Avista Corp 2023 Electric IRP 9-3
Chapter 9: Preferred Resource Strategy
The model solves using the net present value of utility costs given the following inputs:
1. Expected future deficiencies for each state and the system
• Summer Planning Margin (13%, May through September)
• Winter Planning Margin (22%, October through April)
• Monthly energy targets by state
• Monthly clean energy requirements
2. Costs to serve future retail loads as if served by the wholesale marketplace (from
Aurora)
• Existing resource and energy efficiency contributions
• Operating margins
• Fixed operating costs
• Capital costs
• Greenhouse Gas (GHG) emission levels
• Upstream GHG emission levels
• Operating GHG emissions
2. Supply-side resource, energy efficiency and demand response options
• Fixed operating costs
• Return on capital
• Interest expense
• Taxes
• Power Purchase Agreements
• Peak contribution from Western Resource Adequacy Program (WRAP)/
E3 regional study
• Generation levels
• GHG emission levels for Climate Commitment Act (CCA)
• Upstream GHG emission levels (WA only)
• Construction and operating GHG emissions (WA only)
• Transmission costs
3. Constraints
Avista Corp
• Must meet energy, capacity, and Washington's clean energy shortfalls
without market reliance for each state
• Named Community Investment Fund minimum spending (WA only)
• Resource quantities available to meet future deficits
2023 Electric IRP 9-4
Chapter 9: Preferred Resource Strategy
The model's operation is characterized by the following objective function:
Minirr,ize: (WA "Societal" NPV2023-45) + (ID NPV2023-45)
Where:
• WA NPV2023-45 = Market Value of Load + Existing & Future
Resource CosUOperating Margin + Social Cost of Greenhouse Gas
+ Non-Energy Impacts+ Energy Efficiency Total Resource Cost
• ID NPV2023-45 = Market Value of Load+ Existing & Future Resource
CosUOperating Margin + Energy Efficiency Utility Resource Cost
Subject to:
• Generation availability and timing
• Energy efficiency potential
• Demand response potential
• Winter peak monthly requirements
• Summer peak monthly requirements
• Annual energy monthly requirements
• Washington's clean energy monthly goals
• Named Community Investment Fund outlays (WA only)
Preferred Resource Strategy DER Selections
Currently there are three major energy policies in Washington impacting long-term
resource strategies with major uncertainties. None of these policies are developed to a
level needed to properly optimize resources. The current policy issues are: 1) CETA's
determination of "use" for compliance with the 2030 primary compliance standard, 2) the
Climate Commitment Act's (CCA) impacts on multijurisdictional utilities compliance
requirements for importing power into the State of Washington, and 3) state building code
changes to residential and commercial buildings' use of natural gas.
In addition to the uncertainty in policies, there are also uncertainties in projected resource
costs due to supply chain issues, inflation concerns, development of new technologies
and the influences of market price conditions on analysis and future acquisitions. To
address these uncertainties, Avista presented its assumptions to the IRP Technical
Advisory Committee (TAC) to discuss any concerns and seek input on alternative options
for Avista to consider. This IRP reflects Avista's decisions based on input from its TAC.
The PRS includes several components: 1) required investments as part of A vista's
commitment of NCIF monies, 2) demand response or retail rate pricing strategies, 3)
energy efficiency, 4) supply-side resources, and 5) transmission needs.
Washington Named Community Investment Fund
This IRP includes projects from the NCIF approved4 in Avista's first CEIP. This fund
targets specific communities with additional investments beyond those traditionally used
4 Docket UE-220350, Order 01
Avista Corp 2023 Electric IRP 9-5
Chapter 9: Preferred Resource Strategy
in least cost resource acquisitions to improve disadvantaged communities as the industry
transitions to cleaner resources. The fund is approximately 1 % of revenue requirement or
$5 million. This IRP attempts to estimate resource decisions based on available funding
with impacts to resource strategy. The NCIF targets spending for the following objectives
of the total available funding :
• 40% or up to $2 million dedicated to supplement and support Avista's targeted
energy efficiency efforts.
• 20% or up to $1 million dedicated to distribution resilience efforts.
• 20% or up to $1 million dedicated to incentives or grants to develop projects led
by local customers or third parties.
• 10% or up to $500,000 for new targeted outreach and engagement efforts
specifically for Named Communities. This is intended to reduce barriers to
participation for Named Communities' access to clean energy.
• 10% or up to $500,000 for all other projects, programs, or initiatives.
The IRP focuses on ensuring enough energy or capacity is created to meet customer load
at the right time. Specific NCIF projects are unknown and will be developed over time
based on direction from the communities Avista serves. Due to the unknown nature of
future projects, the IRP needs to be adjusted to account for these benefits and reduce
acquisition targets for other resources. Therefore, actual decisions for funding may or
may not impact overall resource needs and are subject to Avista's Equity Advisory
Group's (EAG) recommendations for using these funds. Given an IRP cannot forecast
specific future projects chosen, this analysis is designed to estimate possible projects by
selecting resources or energy efficiency programs meeting NCIF objectives. This is done
by requiring the model to select an additional $2 million dollars of EE (upfront spending
estimated by the present value of the UCT cost) and $0.4 million of incremental supply­
side DER cost each year (after tax incentives).
The result of this effort includes approximately 8 MW of community solar using
Department of Commerce funding for this planning horizon. After funding expires, the
NCIF could add approximately 2 MW of additional locally distributed solar with 9 MWh of
energy storage designed to directly benefit customers residing in Named Communities.
The quantity of community solar is a direct result of state (Commerce) and NCIF funding
covering 100% of the solar costs including land and administration costs. The total
amount of solar added to benefit these communities will be directly related to available
funding and project limitations. In addition to solar, Avista's energy efficiency targets are
2.25 GWh higher to reflect additional investments in Named Communities through 2045. 5
The following forecast of these specific resources is in Table 9.1 . Both energy efficiency
and solar decrease towards the end of the forecasted period. Solar decreases are due to
the end of the state funding incentives. Energy efficiency savings beyond 2033 will be
5 For energy efficiency, energy potential is estimated using low-income vs. non-low income and does not
include geographic areas at this time.
Avista Corp 2023 Electric IRP 9-6
Chapter 9: Preferred Resource Strategy
insignificant as compared to prior years as most of the energy efficiency potential was
achieved in the first 10 years.
Table 9.1: NCIF Resource Selection
Program Distribution Level Distribution Energy Efficiency
Solar Level Storage
2024-2033 791 kW per year Not selected 222 MWh per year
2034-2045 150 kW per year 193 kW (773 kWh) 2.2 MWh per year
per year
Demand Response Selections
Demand Response and/or retail rate load control programs could be integral to Avista's
strategy to meet peak customer load requirements with non-emitting resources. Avista
added 30 MW of industrial demand response since the 2021 IRP and agreed to pilot three
DR programs (see Chapter 5). There is uncertainty in the treatment of DRs in the
upcoming WRAP with regards to what amount will meet the planning reserve margin
(PRM) due to the time duration limits and load snap back effects. Further, some programs
using retail rates, such as Time of Use (TOU) are not dispatchable and are dependent on
the customers' willingness to participate at the time of the DR event.
In this analysis, voluntary TOU rates in Washington State are the only cost-effective DR
option in the PRS given the cost and benefit assumptions. Avista will pilot this project to
determine if the program delivers the expected benefits. If the program is implemented
post-pilot, it would begin in 2025 at the earliest for all Washington customers. The total
estimated peak savings from TOU rates is nearly 7 MW by 2045.6 This program is cost­
effective over other programs due to significant energy savings assumed for the program
rather than just its load reduction capability. Avista will also pilot Peak Time Rebate (PTR)
and a water heater direct control program over the next two years. These pilots may result
in additional cost-effective selections as the IRP assumptions will be updated based on
information gathered in the pilot process. As for this IRP analysis, DR is not favored in
this plan due to program cost, but on the ability to count on the resource to meet peak
requirements (Qualifying Capacity Credit-QCC) .7 This plan assumes QCCs for DR pilots
will fall to 20% of its capability by the end of the plan, whereas if the QCC was 100% of
the capability, 18 MW would be selected in Washington and 9 MW in Idaho. The additional
programs selected in this scenario include PTR and Variable Peak Pricing (VPP).
Energy Efficiency Selections
Energy efficiency meets more than 27% of all future load growth, where prior IRP
forecasts found EE met nearly 70% of future load growth. This decline is related to
6 AEG estimate a non-voluntary TOU program would yield 40 MW of savings by 2045.
7 QCCs are further described in Chapter 4.
Avista Corp 2023 Electric IRP 9-7
Chapter 9: Preferred Resource Strategy
expectations of new load from electric transportation and building electrification using
efficient appliances and market saturation of efficient technologies. Over 2,600 individual
EE measures were studied in this IRP.8 Avista models EE programs individually to ensure
each program's capacity and energy contributions are valued in detail for the system. This
method ensures an accurate accounting of peak savings.
Avista's load forecast (described in Chapter 2) is net of future EE savings. This EE
selection exercise is trying to determine the amount of EE and the specific cost-effective
programs Avista should pursue. Avista adds the selected quantity of efficiency savings
back to the load forecast through an iterative technique in PRiSM until the amount of
energy efficiency selected and the amount of load added, are nearly equal.
Over the course of the plan, 695 cumulative gigawatt-hours are saved through EE
between 2024 and 2045. When considering transmission and distribution losses, loads
are 85 aMW less with these programs. Figure 9.2 shows total energy and peak hour
savings by state for both winter and summer. Winter peaks are reduced by nearly 80 MW
and summer peaks are reduced by 84 MW. Over the IRP planning horizon, 29% of new
EE comes from Idaho customers and 71 % from Washington customers. Washington has
more EE savings than Idaho relative to its share of load because of the higher avoided
costs driven by CETA and other Washington regulations.
1,000
900
800
700 II) ... ::, 600 0
J:
:i:: 500 ro ~ ro 400 .!21
(.!) 300
200
100
Figure 9.2: Energy Efficiency Annual Forecast
-WA-GWh
c::=:J ID-GWh
-summer-Total MW
-winter-Total MW
~ ~ m ~ ro m o N M ~ ~ m ~ ro m o ~ N M ~ ~ N N N N N N M M M M M M M M M M ~ ~ ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
100
90
80
70
60 .l!l -ro
50 ~ ro Cl
40 Ql ::!!:
30
20
10
0
8 Past IRPs included over 7,000 measures, to be more efficient this IRP combines similar programs to
reduce the options.
Avista Corp 2023 Electric IRP 9-8
Chapter 9: Preferred Resource Strategy
Most EE savings are from commercial customers (58%), followed by residential
customers (28%), with the remainder from industrial customers. The greatest sources of
EE, at nearly 67%, are from lighting and space heating/cooling measures. Figure 9.3
shows the program type by share of the total savings by percentage through 2045.
Washington Biennial Conservation Plan
The amount of energy efficiency identified in the PRS will lead to specific program creation
in Washington and Idaho. The IRP informs Avista's EE team in determining cost-effective
solutions and potential new programs for business planning, budgeting, and program
development to meet Washington's Energy Independence Act (EIA) Biennial
Conservation Plan (BCP) targets. 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 Avista'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 9.4 shows the annual selection of new energy
efficiency compared to the 10-year pro-rata share methodology.
Figure 9.3: Energy Efficiency Savings Programs by Share of Total
Interior Lighting
Space Heating/Cooling
Electronics
Refrigeration
Process
Water Heating
Appliances
Food Preperation
Ventilation
Office Equipment
Motors
Miscellaneous
Exterior Lighting
Avista Corp
~================================-.-r-=-3-=-s.6=0
1c,-o -~
4
?.?% ! 10.7%
-------------~1 31.3%
r:::7 4.1%
--~1 6.8%
g 2.4%
2.4%
0 2.0% =:J 2.2%
□ Idaho □Washington
2023 Electric IRP 9-9
Chapter 9: Preferred Resource Strategy
Figure 9.4: Washington Annual Achievable Potential Energy Efficiency (Gigawatt Hours)
350
317
c::::JSelected EE
300 -10 Yr Pro Rata
250
(/) ...
:::I
0 200 :I: ... ... ra
== 150 ra Cl
(.!)
100
50
0
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
For the 2024-2025 Conservation Potential Assessment (CPA), the two-year achievable
potential is 50,899 MWh for Washington. The pro-rata share of the utility's ten-year
conservation potential is 63,374 MWh and is used in the calculation of the biennial target.
Table 9.2 contains achievable conservation potential for 2024-2025 using the PRiSM
methodology. Also included below in Table 9.2 is the energy savings expected from the
2024 and 2025 feeder upgrade projects shown.
Table 9.2: Biennial Conservation Target for Washington Energy Efficiency
2024-2025 Biennial Conservation Target (MWh)
CPA Pro-Rata Share 63,374
EIA Target 63,374
Decoupling Threshold 3,226
Total Utility Conservation Goal 66,600
Excluded Programs (NEEA) -10,162
Utility Specific Conservation Goal 56,438
Decoupling Threshold -3,226
EIA Penalty Threshold 53,212
Preferred Resource Strategy Resource Selections
The PRS is designed to meet resource needs described in Chapter 4 with generic new
resources as described in the DER (Chapter 5) and supply-side resource (Chapter 6)
chapters. Due to recent acquisitions described earlier, Avista will not need new resources
until the beginning of the next decade. When Avista prepares to acquire these resources,
an all-source RFP will be issued ahead of the need to find the best resource opportunity
to meet the need rather than use specific IRP resource requirements . The resource
Avista Corp 2023 Electric IRP 9-10
Chapter 9: Preferred Resource Strategy
strategy discussed here is based on the best available information for planning purposes
and are a result of expectations of future loads and resource pricing . Due to uncertainty,
Avista will study alternative portfolios discussed in Chapter 10 and will continue to revise
this plan every two years.
Avista separates its two jurisdictions for IRP resource selection due to different state-level
policy objectives and financial evaluation methodologies. To conduct this analysis, each
state is separated by its load forecast along with its planning risk adjustments (totaling
the planning obligation), then existing resources are netted against the obligation for each
state, whereas each resource is split between states using the existing methodology to
allocate resource costs (Production Transmission (PT) ratio) where 64.4% is assigned to
Washington and 35.6% to ldaho.9 Resources are then selected based on the objective
function described on earlier in this chapter to fill any shortfalls.
Supply-Side Resource Retirement or Exits
The resource strategy includes retirement or exit of several resources to the existing
power supply portfolio. The first resource leaving the system is Colstrip Units 3 and 4, at
the end of 2025. These units provide 222 MW of generation capability. Following Colstrip
are approximate retirement dates for several of Avista's natural gas peaking facilities.
While these dates are subject to change, this plan uses these dates as placeholders to
determine need for additional resources. These retirements include Northeast by the end
of 2035, Kettle Falls combustion turbine (CT) and Boulder Park by the end of 2040, and
Rathdrum by the end of 2044. With the Lancaster PPA extension concluding by the end
of 2041, the last remaining natural gas facility is Coyote Springs 2. This resource does
not have a planned retirement year for this IRP but is excluded from the resource stack
for Washington beginning in 2045. Table 9.3 summarizes resource retirement and exit
assumptions.
Table 9.3: Resource Retirements and Exits
Resource Fuel Type Year January
Capacity MW
Colstrip Units 3 & 4 Coal 2025 222.0
Northeast Units A & B Natural Gas 2035 66.0
Boulder Park (1-6) Natural Gas 2040 24.6
Kettle Falls CT Natural Gas 2040 11.0
Rathdrum Units 1 & 2 Natural Gas 2044 176.0
Total 499.6
9 Under the current PT ratio methodology, the ratio would change each year if one state's load grows faster
than the other. In this IRP, the PT ratio is left constant to illustrate resource need without one state gaining
a larger share of the existing resource base.
Avista Corp 2023 Electric IRP 9-11
Chapter 9: Preferred Resource Strategy
Supply-Side Resource Selections (2024 to 2035)
Due to Avista's recent resource acquisitions, the first utility scale resource selection is
200 MW of Northwest wind in 2030 followed by another 200 MW of wind from Montana
in 2032. The model selected these resources earlier than the forecasted actual need, as
they are more cost effective to acquire before the current tax credits expire. These
selections are also constrained by transmission interconnect limit expectations, whereas
Avista estimates only 200 MW of on-system wind can be added to the system prior to
transmission expansion and only 200 MW of Montana wind can be imported without
expanded transmission from Montana. Due to these transmission limitations, the model
selects the resource for Washington only to meet its clean energy targets. The resources
would be economic for Idaho if there are additional low-cost transmission interconnect
opportunities when the new wind is acquired.
The next resource addition before 2035 is a 90 MW natural gas CT for Idaho load
requirements. The resource replaces the lost capacity of Northeast CT and positions the
jurisdiction to overcome future natural gas retirements in 2040 while also meeting
increased load obligations. Table 9.4 summarizes the capacity addition plan through
2035.
Table 9.4: Resource Selections (2024-2035)
Resource Time Jurisdiction Capability (MW) Energy
Period Capability
(aMW)
NW Wind 2030 WA 200 63
Montana Wind 2032 WA 200 97
Natural Gas CT 2034 ID 90 86
Total New Resources 490 245
Supply-Side Resource Selections (2036 to 2045)
To meet aggressive clean energy targets for Washington by 2045 and replace aging
natural gas resources while meeting higher load growth due to electrification preferences
in Washington state, Avista expects substantial resource needs after 2036. Idaho needs
follow load growth and natural gas resource retirements. Table 9.5 outlines the resource
additions and the associated energy production from added resources between 2036 and
2045.
Avista Corp 2023 Electric IRP 9-12
Chapter 9: Preferred Resource Strategy
Table 9.5: Resource Selections (2036-2045)
Resource Time Jurisdiction Capacity Energy
Period (MW) Capability
(aMW)
Renewable Fueled CT 2036 WA 88 31
Long Duration Storage (>24 hr) 2039 WA 52 -1
PPA Wind Renewal 2041 WA 140 53
Renewable Fueled CT 2041 WA 74 26
Natural Gas (ICE) 2041 ID 46 46
PPA Wind Renewal 2042 WA 105 36
Renewable Fueled CT 2042 WA 186 65
Natural Gas CT 2042 ID 102 97
Long Duration Storage (>24 hr) 2043 WA/ID 68 -1
NW Wind 2044 WA 100 31
Long Duration Storage (>24 hr) 2044 WA/ID 50 -1
NW Wind 2045 WA 200 63
Renewable Fueled CT 2045 WA 348 122
Natural Gas (ICE) 2045 ID 65 65
Short Duration Storage (<8 hr) 2045 ID 25 0
Total New Resources 1,649 632
There are two primary technologies selected by the model to solve capacity shortfalls
without using natural gas technologies -these are ammonia-based turbines labeled as
"Renewable Fueled CT' in Table 9.5 and iron-oxide storage labeled as "Long Duration
Storage (>24hr)". Both of these technologies are undeveloped at a commercial utility
scale and can be substituted if the technologies do not materialize, although its
substituted resource would require a new technology or requiring more lower duration
storage resources at a higher cost. A significant risk to meet future load in Washington is
the failure of storage technologies materializing, placing the 100% clean energy targets
in significant jeopardy without compromising reliability or affordability.
The Idaho capacity additions are, for the most part, natural gas CT in 2042 and natural
gas Internal Combustion Engines (ICE) in 2041 and 2045. Long-and short-duration
energy storage fill smaller capacity needs during this period. In total, 280 MW of capacity
are required for Idaho customers.
For Washington State, 1,370 MW of capacity is required to replace capacity resources
and further develop additional clean energy to meet 2045 targets. Over the last decade
of this plan, Washington customers, who represent 64% of existing load, demand 83% of
the new capacity or 480% more generating capacity than Idaho customers. The plan
outlines 545 MW of additional wind capacity, whereas 245 MW of this total could be met
with extensions of existing wind PPAs. The other wind selections are from off-system
resources to avoid building higher cost transmission on the Avista system. The remaining
Avista Corp 2023 Electric IRP 9-13
Chapter 9: Preferred Resource Strategy
824 MW are capacity resources additions are long-duration storage or renewable fuels,
whereas renewable fuels are in fact long duration storage, but have a separate energy
consumption intake.
Renewable Fuels
Avista estimates a need of 696 MW of renewable fueled CTs. This IRP assumes the fuel
is purchased within a future hydrogen/ammonia fuel market. The renewable fuel will
require substantial clean electrical energy production to meet the demand. For example,
current ammonia round trip efficiency with a CT is approximately 13.4%, meaning for each
MWh of ammonia power will require 7.5 MWh of a renewable resource to be created
earlier in the process. Avista anticipates additional renewable resources beyond those
identified in the PRS will need to be developed by the fuel supplier or will be buying power
from either the wholesale market or a utility.
The amount of renewable production for the expected case of this study to satisfy the CT
requirements is 376 aMW, but in a 95th percentile scenario (i.e. low water year) 953 aMW
is required. To put this into perspective the fuel requirements is equal to 1,500 MW (AC)
of solar for the expected case and 3,800 MW for the high scenario. Avista anticipates
much of the fuel can be produced by a combination of electric market over supply, but it
is likely additional renewable resources will be required. Due to the varying fuel
requirements ammonia storage and transportation will be key to ensuring electrical
reliability, at minimum four 30,000 tonne tanks would be required to ensure reliability for
Avista's Washington demand.
System Overview
Figures 9.5 through 9.7 summarize the future resource additions by combining the
existing portfolio of resources, with contracted additions, and future resource selections
from this plan. As shown in Figure 9.5, the resource portfolio exceeds winter peak
planning requirements through 2039, then is balanced once it must fill resource deficits
from natural gas retirements and load growth with new resources. The end of the plan
relies on storage and renewable fuels to satisfy winter peak requirements. The solid black
line represents the planning load level, including the planning margin, and the dotted line
is the expected peak load given an average coldest weather event.
The summer capacity position in Figure 9.6 is similar to the winter position where the
portfolio has excess capacity, but in this comparison the portfolio should stay above peak
needs as the winter peak position is the binding constraint for new resources. The solid
black line represents the planning load level including the planning margin, and the dotted
line is the expected peak load given an average hot weather event.
A vista's annual energy position (Figure 9. 7) is long compared to annual average needs
due to two factors: 1) excess energy in the springs months from hydro runoff creates an
extreme long position in one quarter compared to others, 2) Avista plans its system to
peak load requirements and if the generation used to serve peak requirements creates
Avista Corp 2023 Electric IRP 9-14
Chapter 9: Preferred Resource Strategy
energy it will be excess to the average need, but can be sold to benefit customers if the
resource is economic to operate. The solid black line represents the planning load level
including the risk of load exceeding expected average weather conditions and/or
renewable energy such as hydro, producing less generation than anticipated in a normal
year. The dotted line is the expected average load with normal weather conditions.
Figure 9.5: System Winter Capacity Load & Resources
3,000
2,500
2,000
(/) -~
-------------------------------~ 1,500 ra Cl (l) :a:
1,000
New Solar/Wind Existing Natural Gas
500 -Existing Coal New Natural Gas
New Renewable Fuels New Energy Storage
-Planning Load --Expected Load
'SI" L() (!) r--co 0) 0 ~ N (") 'SI" L() (!) r--co 0) 0 ~ N (") 'SI" L()
N N N N N N (") (") (") (") (") (") (") (") (") (") 'SI" 'SI" 'SI" 'SI" 'SI" 'SI" 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N N N
Figure 9.6: System Summer Capacity Load & Resources
3,000
2,500
2,000
(/) --ra
-----------------------~---
---
~ 1,500 ra Cl (l) :a:
1,000
-New Solar/Wind -Existing Natural Gas
500 -Existing Coal New Natural Gas
New Renewable Fuels New Energy Storage
-Planning Load --Expected Load
'SI" L() (!) r--co 0) 0 ~ N (") 'SI" L() (!) r--co 0) 0 N (") 'SI" L()
N N N N N N (") (") (") (") (") (") (") (") (") (") 'SI" 'SI" 'SI" 'SI" 'SI" 'SI" 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Avista Corp 2023 Electric IRP 9-15
Chapter 9: Preferred Resource Strategy
Figure 9.7: System Annual Energy Load & Resources
2,000
1,800
1,600
rJ) 1,400
~ ~ 1,200
Cl ~ 1,000
Q)
Cl ~ 800
Q) ~ 600
400
200
'<I" LI') (D
N N N 0 0 0 N N N
New Natural Gas
-Existing Coal
I'--(X) Ol 0 ~ N ('") '<I" N N N ('") ('") ('") ('") ('")
0 0 0 0 0 0 0 0 N N N N N N N N
Transmission & Interconnection Requirements
-Existing Natural Gas
New Renewable Fuels
-Planning Load
LI') (D I'--(X) Ol 0 ~ N ('") '<I" LI')
('") ('") ('") ('") ('") "<t "<t '<I" '<I" "<t "<t 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N
Chapter 7 outlines the transmission investments required for each supply-side option.
While actual transmission needs are difficult to estimate until resource procurement is
made due to location specific requirements, the IRP selection can be helpful to guide
resource decisions for complex multi-year transmission needs. Without new transmission
construction, some resource generation will just not be available for delivery to customers.
The PRiSM model estimates resource selection based on direct project cost,
interconnection, and delivery cost. Selection can occur where a more expensive resource
is preferred to avoid a higher total cost due to transmission interconnection. By the 2040s,
Avista is likely to either have consumed the lower cost connected resources or other
utilities may export these resources off Avista's system . In either case, Avista will need to
reinforce its transmission system in renewable rich but transmission congested areas ,
such as the Big Bend (Othello, WA) area to be able to provide resources to customers in
the future. Due to the historical long-lead time to develop transmission, Avista's
transmission department will evaluate long-term system needs and begin permitting and
land acquisitions as early as possible.
The PRS also identifies the potential for new transmission needs in the North Idaho and
Spokane areas. For example, long duration storage using ammonia-based turbines could
be sited at greenfield or existing sites, but subject to area load growth, state policies, and
capacity needs; additional reinforcement between North Idaho and Spokane will be
needed if the resource is sited in these areas. Because of the urban nature of these areas,
Avista's transmission group will need to investigate how to alleviate these constraints.
Avista Corp 2023 Electric IRP 9-16
Chapter 9: Preferred Resource Strategy
Lastly, Avista may need additional transmission to reach existing or new markets. With
the amount of off-system wind resources selected , 200 MW of Montana wind 10 in the first
half of the plan and 500 MW of Northwest wind in the second half of the plan, the model
selected off-system wind with wheeling charges over on-system wind due to the cost of
building new transmission. However, the ability to import resources from off-system could
compete with other utilities also trying to bring resources with Avista's system to their
systems. Further, with the amount of variable energy resources (VER) (subject to storage
charging), Avista will be an exporter of energy as the amount of acquired resources will
likely exceed average customer load and Avista may not be able to sell the excess
generation without expanding existing transmission capacity or utilizing neighboring
systems. Purchasing non-firm transmission could be an option, but its availability may
have limitations due to regional pressures to acquire transmission for 1-5 corridor loads.
A Regional Transmission Organization (RTO) solution could help relieve some of these
pressures, but further analysis is required to study external connection requirements as
well as the cost and benefits of an RTO. Avista plans to further analyze market related
transmission needs in preparation of the 2025 IRP.
Market Risk Analysis
As discussed in Chapter 4, Avista has changed its approach to capacity planning. The
2021 IRP utilized a loss of load probability (LOLP) analysis to determine capacity
additions necessary to achieve a 5% LOLP. In this IRP, Avista is utilizing metrics, called
Qualifying Capacity Credits (QCCs), from the WRAP program and other regional studies
to drive capacity additions in the PRS. Inherent in this approach is the potential for
increased reliance within an organized energy market.
To understand market reliance throughout the year a modified version of the reliability
model used in the 2021 IRP LOLP analysis was used. The model is a linear optimization
dispatch model based in Excel using Lindo Systems' What'sBest. The model optimizes
to serve load with a specified amount of generation from run of river facilities, contracts,
and renewables. The balance is then met with dispatched generation from hydro with
storage, thermal generation, batteries and market purchases and sales. The dispatch is
linearly optimized to minimize costs from thermal generation and market purchases.
A risk evaluation is done by running the model repeatedly, each time randomly selecting
a weather year driving load and renewable generation and a hydro year for
hydrogeneration, both run of river generation and available water for dispatch of storage
hydro projects. The model also integrates forced outages based on rates established for
each generation resource. For each year, the model output includes any hours where
load could not be met by generation, battery storage, or market purchases, thereby
creating a loss of load event. The model output also includes the full hourly market
10 Assumes transmission is available from other plant closures and new facilities will be constructed to
integrate new wind resources to existing transmission.
Avista Corp 2023 Electric IRP 9-17
Chapter 9: Preferred Resource Strategy
purchases for each year. Market prices were taken from the Aurora stochastic price
analysis described in Chapter 8.
Four scenarios were run for this analysis: 1) 2030 PRS with an hourly market purchase
limit of 330 MW, 2) 2030 PRS with an hourly market purchase limit of 1,000 MW, 3) 2045
PRS with an hourly market purchase limit of 330 MW, and 4) 2045 PRS with an hourly
market purchase limit of 1,000 MW. Each scenario was run 1,000 times. Historically,
Avista used the 330 MW market limit to set thresholds for reliability, but with the
development of the WRAP and its resource sharing benefits during peak events, this
threshold is moved to 1,000 MW to understand market dependance during peak events.
Results were evaluated by averaging the market purchases for each hour of the day for
each month. Both all hours of the year and potential market constrained hours were
analyzed. Market constrained hours are those days that the daily average temperature is
below 2 or above 83 degrees Fahrenheit. Those days are considered market constrained
hours because at these temperature conditions many utilities in the region would be
experiencing above average load and market liquidity would be reduced.
2030 PRS 330 MW Market Purchase Limit
The LOLP for this scenario was 0.40%, with only two simulations resulting in unserved
energy. The matrix below shows the average market hourly purchase for each month by
hour. Market purchases are driven by market price, available hydro, and renewable
production. As shown in Figures 8.17 through 8.20 from Chapter 8, prices are lower during
the mid-day and highest during hours 18-24. Market prices in 2030 were generally lower
than the model price for thermal generation, therefore the model selected market
purchases during low-cost hours rather than thermal generation. This does not reflect a
market reliance, rather optimization based on market prices and the cost of thermal
generation. Average market purchases during the mid-day are near the modeled max of
330 MW, but do not reach that level as show in Table 9.6. During May and June market
purchases are less than 30% of the model max due to the abundance of hydro energy.
During periods of a regionally constrained market, the limit of 330 MW was reached during
mid-day and neared the market limit in all other hours in all months except for March ,
April, and May. Generally speaking hours 7, 8 and 18 are the highest load hours during
winter months and hours 16 to 18 are the highest in the summer months. As shown in the
lower Table 9.6 chart, the model shows market reliance toward the market cap in summer
months, but winter months appears to not reach the maximum allowable market in these
hours.
Avista Corp 2023 Electric IRP 9-18
1
2
3
4
.c 5
§ 6
~ 7
8
9
10
11
12
Chapter 9: Preferred Resource Strategy
Table 9.6: 2030 Average Market Purchases with 330 MW Market Limit (aMW)
All Hours
Hour
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
77 105 117 125 119 74 36 46 144 235 271 278 279 277 274 250 56
84 116 131 138 124 59 27 68 221 298 314 318 315 313 310 297 155
3
4
87 112 125 122 80 38 65 229 308 320 323 3Qa 8 ~1 320 310 245 27
39 48 51 44 23 18 121 230 273 286 289 288 286 283 279 258 184 16
8 11 12 9 5 5 35 66 83 87 88 88 87 87 82 61 25 2
19 23 23 21 15 18 52 80 89 90 90 91 89 80 61 37 15 5
3
5
2
0
2
3
5
1
0
4 10 22 48
2 4 18 48
5 10 25 55
2 4 10 22
0 0 2 11
33 40 38 40 38 71 201 260 270 275 278 282 279 257 219 150 88 50 18 11 11 21
8 23
32 36
46 56 59 62 51 67 212 282 292 296 298 302 302 290 265 203 138 65 11 8 8 203543
29 35 35 34 28 25 131 260 277 281 283 285 286 284 264 177 86 25 9
42 50 50 48 35 21 51 220 276 286 287 286 283 280 271 195 42 6 5
64 83 92 99 89 47 33 161 276 301 302 301 297 297 287 204 19
56 82 88 99 100 72 30 69 166 244 271 274 273 269 266 196 23
4
2
4
2
8 10
6 8
19 24 27
16 25 35
3 4 10 22 42
2 3 9 21 38 '-------------------------~=~-~-----~
1 2 3 4 5 6 7 8
Regional Market Constraint Hours
Hour
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
1 297 304 311 317 325 1SG 330 ~ 330 330 330 330 330 301 273 286 271 262 275 247 268
~ 330 338 330 330 330 330 330 330 298 246 213 253 265 280 286
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2 330 319 338 317 319, __ = ___ :_.,,---~-.. _ _::_:_
3 0 0 0 0 0
4 0 0 0 0 0
.c 5 0 0 0 ~ 6 325 325 ~ 7 276 308
8 265 252 283
9 165 117 205
10 153 188
11 323--32~7---~=~~~i.l,
12 266 292
0
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
2 243 206 234 214 171 112 155 123 -►J:J!"'~-321 7 216 218 238 238 279
208 184 212 250 238
248 250 189
154 113 207
313--=""'--'= 293 319
237 229 203 215 211 242 264
2030 PRS 1,000 MW Market Purchase Limit
The LOLP for this scenario is 0%. The only difference between this scenario and the
previously described scenario was the modeled maximum was increased from 330 MW
to 1,000 MW. This suggests the two loss of load events in the previous scenario were
alleviated by market availability. The market purchase pattern is similar to the previous
scenario, but the values are greater, though not reaching the model maximum of 1,000
MW as shown in Table 9.7. This illustrates the difference between market price and the
cost of thermal generation. Given the low prices in the middle of the day and system
flexibility, Avista is able to shift its energy storage at its hydro system to minimize capacity
purchases during the highest load in hour 18. During periods of a regionally constrained
market there is an increase in purchases across all hours of the day in comparison to the
"all hours" scenario, though in most instances did not reach the model maximum of 1,000
MW. It is noteworthy when comparing these results to the 330 MW market limit, the
summer month's peak hours use more market during high low hours, this is likely due to
pricing arbitrage to take advantage of mid-day lower prices.
Avista Corp 2023 Electric IRP 9-19
Chapter 9: Preferred Resource Strategy
Table 9.7: 2030 Average Market Purchases with 1,000 MW Market Limit (aMW)
All Hours
Hour
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
2
3
4
.r: 5
§ 6
~ 7
.r:: c 0 ~
8
9
10
11
12
1
2
3
4
5
6
7
8
9
10
11
12
74 107
64 103
59 87
21 28
7 10
16 19
18 23
35 43
28 36
48 60
62 89
44 70
2
228 276
303 379
0 0
0 0
0 0
322 318
302 312
285 277
86 135
88 263
369 394
174 249
127 140 130 71
126 140 125 50
103 102 56 23
29 23 9 8
10 7 4 2
19 17 12 9
20 20 17 39
43 45 32 49
36 33 23 19
59 56 33 16
106 119 95 37
81 98 95 55
3 4 5 6
331 363 361 240
396 390 434 271
0 0 0 0
0 0 0 0
0 0 0 0
251 260 266 350
275 258 268 294
275 304 285 306
203 193 158 167
247 234 113 102
418 479 444 329
276 313 315 254
36 52 223 425 528 554 554 544 531
24 88 396 622 707 726 712 695 669
74 382 604 883 704 888 884 657 629
105 274 380 423 428 418 409 384 364
25 67 96 106 108 108 106 108 99
42 88 113 119 121 127 127 113 84
187 346 399 434 464 500 516 464 373
238 429 495 531 554 590 607 572 491
168 423 478 493 505 514 526 528 474
61 397 547 574 575 563 545 525 499
30 265 570 668 673 670 652 643 601
25 77 252 422 500 515 511 498 487
Regional Market Constraint Hours
Hour
7 8 9 10 11 12 13 14 15
268 328 522 665 773 785 774 749 726
352 499 819 922 989 981 en 972 952
0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0
425 457 508 427 338 299 304 318 240
454 612 696 777 839 882 919 886 764
502 677 772 846 894 95897.9 960 856
492 923 -895 912 907 916 920 919
236 845 913 833 834 836 832 820 812
420 818 IN 1IIIO 000 :tG0t NI t81 982
280 407 598 708 756 756 753 707 713
2045 PRS 330 MW Market Purchase Limit
457 581 2 2 2 2 8 18 44
590 216 3 1 1 1 3 12 35
559 354 23 3 3 4 7 13 35
300 166 12 2 1 2 3 6 14
67 21 1 0 0 0 0 3 14
44 14 4 2 1 1 0 9 26
232 123 69 24 9 9 18 25 26
328 195 82 13 9 8 19 31 36
268 113 32 8 7 10 22 27 30
317 45 6 5 6 8 18 29 41
352 18 3 3 3 4 9 18 39
315 23 2 2 2 3 8 19 35
16 17 18 19 20 21 22 23 24
641 277 221 250 188 175 174 151 190
943 509 145 140 92 99 245 226 195
0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0
222 196 231 209 172 155 129 131 503
633 533 395 293 193 210 210 421 382
639 552 440 270 486 424 262 190 244
527 346 109 38 22 20 166 335 143
564 350 0 0 0 81 172 238 299
841 341 288 265 274 198 239 223 345
506 278 185 179 147 162 202 200 183
The LOLP for this scenario is 0%. Market purchases follow a similar pattern as the 2030
scenarios with the most significant market purchases occurring in the mid-day when
prices are low. In the 2045 scenario the cost of thermal generation is increased largely
due to the addition of higher cost renewable fueled (ammonia) turbines. This high-priced
fuel increases the use of market purchases leading to the maximum market purchases
as shown in Table 9.8, but available during high stress hours. In market constrained hours
the market max of 330 MW is used in most hours except during the months March, April,
and May.
Avista Corp 2023 Electric IRP 9-20
Chapter 9: Preferred Resource Strategy
Table 9.8: 2045 Average Market Purchases with 330 MW Market Limit (aMW)
All Hours
Hour
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
1 312 324 323 323 323 314 260 314 328 330 330 330 330 330 330 308 203 189 176 230 298 317
2 311 318 318 319 317 289 211 241 325 _, 330 • 330 330 aao • 324 165 147 118 138 237 296
3 279 293 296 295 264 205 213 313 • -, • sao • 330 • ., 112 112 96 109 187 252
4 75 87 91 79 44 36 173 279 305 310 313 313 314 314 314 309 260 12 9 9 11 25 46
.c 5 13 16 15 12 7 3 31 63 79 83 86 88 90 91 86 65 32 17 9 7 6 4 13 c 6 24 28 27 25 17 23 70 106 116 118 119 122 125 117 97 76 60 60 48 29 16 13 12 23 0 ~ 7 125 131 114 113 107 158 269 303 311 315 318 321 322 318 302 268 231 195 114 83 64 84 118 138
8 205 202 188 184 170 199 292 314 320 323 325 328 327 327 328 321 309 265 111 89 91 178 249 251
9 197 183 158 157 152 161 268 313 318 320 321 322 324 325 323 317 291 136 88 86 88 137 207 223
10 244 236 219 217 211 208 260 320 3iatQ-3J8321328328 323 286 82 87 85 95 163 238 262
11 303 303 301 303 300 282 261 315 328 ____
380 235 134 142 132 133 190 267 297
12 315 316 312 314 315 311 272 284 324 329121330330330330 m 251 171 181 169 163 204 279 311
Regional Market Constraint Hours
Hour
5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 24
1 ---2 l30 3IO -3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
.c 5 0 0 0 0 c 6 0 ~ 7
8
9
10
11
12
2045 PRS 1,000 MW Market Purchase Limit
The LOLP for this scenario is 0%. It follows a similar pattern to the previous scenario with
market purchases highest during the mid-day hours, and less market purchases during
months with increased hydro production. During market constrained hours the market
maximum was reached during mid-day hours and there was an increase of use across
all hours, except during the months of March, April , and May as shown in Table 9.9.
The conclusion of this study indicates with expensive variable cost units (Renewable
Fueled CTs), the Avista system will be able to optimize lower cost market power (if
transmission allows) and utilize the CT capacity for reliability. Given the desire of the
model to maximize the allowable market purchases indicates a need to ensure
transmission is available to future energy markets.
Avista Corp 2023 Electric IRP 9-21
Chapter 9: Preferred Resource Strategy
Table 9.9: 2045 Average Market Purchases with 1,000 MW Market Limit (aMW)
All Hours
Hour
2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
2
3
4
.c 5
§ 6
::ii 7
.c c 0 ::ii
8
9
10
11
12
1
2
3
4
5
6
7
8
9
10
496
306
167 ,_
32
14
21
64
171
175
274
362
464
790
755
0
0
0
533
429
506
346
451
534 530
347 358
212 229
38 36
16 14
23 21
71 57
162 142
176 139
279 243
394 393
499 483
2 3
833 845
836 883
0 0
0 0
0 0
566 564
400 370
398 359
398 472
523 630
538 534 440 211 247
367 347 211 101 246
222 135 63 151 566
28 10 10 123 337
11 7 1 25 68
18 11 9 60 126
56 49 107 302 452
138 112 159 385 533
143 128 127 352 523
242 205 159 322 634
415 375 268 237 648
502 502 435 232 376
4 5 6 7 8
872 878 806 630 588
918 888 740 323 659
0 0 0 0 0
0 0 0 0 0
0 0 0 0 0
487 526 622 613 631
345 319 384 530 657
352 303 347 589 748
417 471 521 544 744
503 658 626 409 770
576 835 902 918 929 932 936 933j 533 156
693 877 919 929 938 937 938 940 706 158
823 877 889 891 898 896 893 892 753 201
472 517 535 541 553 550 543 520 319 38
95 104 110 114 120 124 117 83 33 21
151 161 169 182 194 180 138 89 60 63
505 556 599 662 713 709 646 519 381 289
591 640 679 727 775 793 781 731 654 433
572 583 608 632 669 691 690 640 503 185
731 735 731 735 740 735 739 685 407 78
861 898 894 902 906 908 905 809 234 112
687 852 890 901 909 912 919 827 278 121
Regional Market Constraint Hours
Hour
9 10 11 12 13 14 15 16 17 18
935 984 1000 1000 1000 1000 1000 1000 892 327
969 1000 1000 1000 1000 1000 1000 1CIGO 932
0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0
642 759 691 652 756 732 509 532 484 561
747 843 951 979 IIIO 968 892 755 595
842 927 115 980 698
893 905 .. 906 355
913 9S3 973 952 151
11 844 902 906 941 1188 867 846 ,.lCIGQ 366
12 730 756 766 793 824 780 691 852 969 913 547 279
Environmental Impacts
177 145 111 175 334
141 118 81 83 146
82 82 67 74 91
10 7 8 8 13
16 9 6 5 5
51 30 16 12 15
136 82 59 80 101
111 74 70 172 276
100 93 96 160 206
92 89 102 167 238
128 106 92 146 239
142 116 93 137 266
19 20 21 22 23
345 268 379 679
283 250 334
0 0 0
0 0 0 0 0
0 0 0 0 0
408 358 356 326 226
421 330 319 322 341
254 195 205 469 715
387 381 169 974 722
311 267 511 904 723
376 299 284 450 726
306 262 262 370 557
Avista's recent changes to its resource portfolio significantly improves its environmental
footprint. Transferring Avista's percent ownership of Colstrip Units 3 and 4 to
Northwestern Energy at the end of 2025 will significantly reduce GHG and other air
emissions. While this transfer does not retire the plant nor eliminate emissions, it does
meet Washington's and Avista's own clean energy goals and will allow Montana to make
their own decisions regarding coal. The additions of hydro, wind, and biomass power from
recent RFPs increases Avista's percentage of clean energy on the system. Figure 9.8
illustrates the increases to clean energy by year and by jurisdiction . The chart compares
total annual clean energy production for each state's allocated share of energy11
compared to the load, whereas in Washington, Avista will need to produce more clean
energy than its load to meet the 100% clean energy target. With its already high clean
energy portfolio, the Idaho jurisdiction does not need to add additional energy due to cost
constraints. On a system basis, the portfolio by 2045 could be 92% clean energy as
11 This does not include potential transfers of clean energy between states to satisfy CETA requirements.
Avista Corp 2023 Electric IRP 9-22
463
244
122
23
18
29
92
253
219
298
330
414
24
797
605
0
156
488
605
696
644
88
730
Chapter 9: Preferred Resource Strategy
compared to load, although when comparing to retail sales Avista would be generating
97.3% clean energy compared to retail sales (not shown).
Figure 9.8: System Clean Energy Ratio Compared to Load (Select Years)
'0
110'll.
100%
90%
80%
! 70'll.
0 60'!(, & j 50'll.
Q. 40% I
30%
20"4
10'4
0'l(,
2024 2030 2035 2040 2045
i 5 ...
Figure 9.9 illustrates the results of the PRS portfolio compared to Avista's assumptions
to meet the primary compliance target where specific CETA obligations prior 2045 are not
known. The primary compliance target estimate is shown in the black dotted line and the
solid line represents net retail load.12 In this case, Avista must use clean energy to meet
its primary compliance target after 2030 (green bars). Any clean energy generation
exceeding load within a month counts towards alternative compliance.13 As illustrated by
Figure 9.9, Avista currently and will continue to create a significant amount of surplus
clean energy as shown in the blue bars. The orange area shows where the model selects
clean energy purchases from the Idaho jurisdiction and the lime area shows where excess
Renewable Energy Credits (RECs) are sold. The PRiSM model limits REC sales to
prevent the model from taking a market position where it could build resources to sell
RECs, therefore REC sales are limited. Avista will sell excess RECs for the benefit of
customers in actual operations. The 100% clean energy target in 2045 will require a
significant amount of additional clean energy as compared with load due to clean energy
production patterns differing from load patterns. Although this may allow the development
of lower cost hydrogen used to create the ammonia to meet the peak load requirements
of this portfolio.
12 Net retail load equals retail sales minus Washington state PURPA resources and voluntary renewable
resources such as the Solar Select Program.
13 This is an IRP assumption as the actual methodology has not been decided by state rule.
Avista Corp 2023 Electric IRP 9-23
Chapter 9: Preferred Resource Strategy
Figure 9.9: Clean Energy to Retail Load Comparison (CETA Requirements)
1,000
900
800
~ 700 Ill ~ 600
Cl ~ 500
~ 400
Ill ~ 300 >
<I: 200
100
-Clean Gen=< monthly net load -Jurisdictional REC Purchases
-Clean Gen > monthly net load REC Sales
-Net Retail Load ---Primary Compliance Target
,q­
N 0 N
LO N 0 N
--
co N 0 N
r--­N 0 N
--
CX)
N 0 N
cr,
N 0 N
--
'(") o(") (")o
~N
'r--­,q-(")
(")o
~N
' ro~ (") ,q­o O NN
LO ,q-
0
N
To illustrate the reductions in greenhouse gas emissions, Figure 9.10 shows the 2021
emission level from Avista's facilities at nearly 3 million metric tons (red line). These
amounts will fall to nearly 1.5 million metric tons after Colstrip leaves the portfolio at the
end of 2025. Afterwards, emissions steadily fall due to reduced natural gas dispatch due
to higher renewable penetration levels in the market and greenhouse gas market pricing
(e.g., CCA impacts). The blue bars represent direct emissions from existing facilities,
while the orange bars are from new natural gas facilities replacing retiring plants. In green ,
is the estimated emissions from either buying market power or selling excess power from
the Avista system. The light blue represents emissions from Avista's generating plant
operations and construction of new resources . By 2045, Avista anticipates an 80%
reduction in greenhouse emissions as compared to the 2021 levels.
Another view of Avista's low GHG portfolio is through the emissions intensity. In this case,
total emissions are compared to Avista's load. Figure 9.11 shows two methodologies for
this comparison. The first method is taking only Avista's direct emissions (blue and orange
bars from Figure 9.10) compared to load. The second accounts for market transactions
(the green bars from Figure 9.10). The black line averages the two methodologies, where
current GHG emissions intensity rates are nearly 600 lbs./MWh declining to 300 lbs./MWh
after Colstrip exits the portfolio, and then continues to decline as natural gas plants
dispatch less frequently or retire. It should also be noted that load is increasing while the
GHG emissions intensity rate is decreasing, indicating a greater emissions decline than
load increase until the mid-2040s.
Avista Corp 2023 Electric IRP 9-24
3.5
3.0
2.5
1/) 2.0 t: ~
C.) 1.5 ·;:: -Q)
~ 1.0 t: 0
:E 0.5
0.0
-0.5
-1 .0
700
600
500
..c:
S: 400 ~ ... Q)
c.. 300 1/) ..c
200
100
Chapter 9: Preferred Resource Strategy
Figure 9.10: System Greenhouse Gas Emissions
11-
-Current Resources
New Resources
-Net Market Transactions
Upstream/Construction/Operations
-Net Emissions
-2021 Generated Emissions
V ~ ID ~ ro m O ~ N M V ~ ID ~ ro m O ~ N M V ~ N N N N N N M M M M M M M M M M V V V V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Figure 9.11: System Greenhouse Gas Emissions Intensity
605 608
L ~ 563 -Direct Emissions
-Net of Market Transactions
-+-Average Rate
319
I 329 331 324 317
-290
l""i' !Iii 265 250 276 275 272 267 258 261 2~ 241
1 l ~84 f 200
V ~ ID ~ 00 m O ~ N M V ~ ID ~ 00 m O ~ N M V ~ N N N N N N M M M M M M M M M M V V V V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
The last emission profiles concerning the resource portfolio includes other major air
emissions from Avista's generation plants. These emissions are well below air quality
standards set by the local air agencies and are controlled at the plant level with the best
available technologies at the time of construction. Avista tracks four major air emissions
in the IRP: Nitrous Oxide (NOx), Sulfur Dioxide (S02), Mercury (Hg), 14 and Volatile
14 Avista does not track mercury emissions at natural gas facilities since it is not a permit requirement, the
emission beyond 2025 are for Kettle Falls based on historical intensity rates, although the most recent study
Avista Corp 2023 Electric IRP 9-25
Chapter 9: Preferred Resource Strategy
Organic Compounds (VOC) at the plant locations in Figure 9.12. The emissions shown
here cover all Avista's owned facilities plus contracted plants where it has dispatch control
rights. Emissions levels in all four categories fall over time, whereas the largest reductions
are from Colstrip leaving the portfolio at the end of 2025. After 2025, the main source of
air quality emissions will be from the Kettle Falls wood waste facility as Avista's natural
gas generating facilities have limited emissions due to lower projected dispatch. Kettle
Falls will see an improvement to air emissions intensity with the steam injection discussed
earlier in the chapter. The selection of ammonia-based generation in the latter years of
the portfolio could result in an increase in NOx emissions from this technology due to the
amount of NOx emitted from the combustion . Since this is a new technology with the
potential to mitigate the emission, the specific emissions levels are currently unknown.
The expectation is that the NOx will be mitigated in order for these plants to be able to
obtain air permits.
1,800
1,600
1,400
~ 1,200 C ~ 1,000
o 800 ·c:
ai :;:i, 600
400
200
0.12
0.10
~ 0.08
C C 0 I-0.06
(.) ·c:
ai :;:i, 0.04
0.02
Figure 9.12: Avista Owned and Controlled Generating Plant Air Emissions
600 NOX
11111111111111111111
V lO(Ol'-C:00)0.-NMVlO<.Ot--COO'>O.-NMVlO N N N N N N ("') ("') M C"') ("') M M ("') M ("') V V V V V V 0000000000000000000000 NNNNNNNNNNNNNNNNNNNNNN
Mercury
••••••••••••••••••••
500
~ 400
C C ~ 300
(.) ·c:
j 200
100
90
80
70
~ 60
C ~ 50
.g 40
j 30
20
10
S02
V lO (Cl I'-CO 0) 0 .-N M V lO (Cl I'-ro 0) 0 .-N M V lO N N N N N N M M M M M M M M M M V V V V V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
voe
Cost and Rate Projections
The IRP cost and rate projection does not include detailed transmission beyond specific
generation acquisition, distribution, administrative, and Operations & Maintenance (O&M)
recovery costs. Rather, the IRP focuses on energy supply costs. Avista assumes these
non-generation costs increase by 3.8% per year to approximate an annual average
customer rate estimate using historic non-power supply cost growth rates. Annual
conducted after the IRP modeling was complete, indicated a non-detect. For Colstrip, a default emission
factor is used for mercury emissions.
Avista Corp 2023 Electric IRP 9-26
Chapter 9: Preferred Resource Strategy
projected rates and revenue requirements are shown in Figure 9.13. Rates are calculated
by the total revenue requirement divided by retail sales and do not represent rate class
forecasts. Also, as rates will be determined by actual investments, this analysis should
only be used for comparative and informational purposes.
The Washington revenue requirement grows at 4.3% a year and rates increase 3.4% a
year, although in the last five years of the study, revenue requirement and rates grow
faster at 7.4% and 6.1 % respectively. Cost and rates for Idaho are generally lower where
the average revenue requirement grows at 3.5% each year and rates are less at 2. 7%
annually. Over the last five years , Idaho rates also increase at a faster rate due to
resource retirements but have a 5.4% revenue requirement increase and 4.2% rates
average increase).
2,500
2,000
-;:; c: 1,500
0
:a: -ti 1,000 0
(.)
500
0
Figure 9.13: Revenue Requirement and Rate Forecast by State
-wA Rev. Req.
ID Rev. Req.
-WA Rate
-ID Rate
0.126
0.113
Incremental Cost Cap Analysis
0.25
0.20
0.15
.c: s: .lll:: ... Q)
0.10 c..
~
0.05
0.00
Avista conducted an incremental cost analysis for Washington-related CETA costs using
the incremental cost methodology provided by rule. The PRS is compared to an
Alternative Lowest Reasonable Cost Portfolio. In this portfolio, PRiSM solves to meet
customer demand without the clean energy requirements and NCIF spending. In this
specific scenario, it also excludes the exit of Coyote Springs 2 in 2045 for Washington
customers. The difference in costs between these studies represents the annual
incremental cost -this value is then compared to a 2% annual rate increase of the
Alternative Lowest Reasonable Cost Portfolio cost. The analysis in Table 9.10 shows
Avista does not reach the cost cap in any of the future 4-year compliance periods but is
much closer in the last 2042 to 2045 window. Since it is unclear if 2045 would be covered
Avista Corp 2023 Electric IRP 9-27
Chapter 9: Preferred Resource Strategy
in this four-year period, there is a strong likelihood given these assumptions, that
exceeding the 2045 cost cap could be used as alternative compliance to meet the primary
compliance requirement.
Table 9.10: 2022-2024 Cost Cap Analysis (millions $)
Avista is concerned with how the Alternative Lowest Reasonable Cost Portfolio is defined.
The concern is if the baseline cost of the portfolio used to estimate the 2% cost cap
includes past higher cost resource acquisitions. One interpretation could be to exclude
any resource acquisition made after 2020 meeting CETA clean energy requirements and
let a capacity expansion model select resources to fill in those capacity/energy deficits or
use a historically based model from a resource plan prior to CETA. Given the options ,
future discussion with stakeholders is necessary since this calculation is critical to
resource selection especially toward the end of the plan and is likely more critical to other
utilities with less clean energy than Avista.
Avoided Cost
Avista calculates the avoided or incremental cost, to serve customers by comparing the
PRS cost to alternative portfolios. These calculations can be useful to evaluate new Public
Utility Regulatory Policies Act (PURPA) agreements or other resource acquisitions. The
calculations here are not used for setting Washington Schedule 62 rates but may inform
its calculation.
Energy Efficiency
The Washington EIA requires utilities with more than 25,000 customers to acquire all cost­
effective and achievable energy conservation.15 Penalties could be accessed for utilities
not achieving EIA targets, further, these targets are also used for setting efficiency
requirements in Washington's CEIP. Avista uses the Total Resource Cost (TRC)16 test
plus non-energy impacts with a social cost of greenhouse gas savings to estimate its cost­
effective energy savings. Idaho only uses the utility cost test. The estimated avoided cost
of energy efficiency in Washington is shown in Figure 9.14 and Idaho's is shown in Figure
9.15. The total 20-year Washington energy avoided cost of energy efficiency is $68.94
per MWh and capacity is $118.44 per kW-yr. These estimates do not include non-energy
benefits as these benefits are program specific and will increase the avoided cost
depending on whether the program has non-energy impacts.
15 The EIA defines cost effective as 10% higher cost than a utility would otherwise spend on energy
acquisition .
16 See Chapter 5 for further information on the TRC and UCT methodologies.
Avista Corp 2023 Electric IRP 9-28
Chapter 9: Preferred Resource Strategy
Idaho avoided cost is less due to the exclusion of clean energy premiums, Power Act17
preference, and avoidance of the social cost of greenhouse gas. Idaho energy avoided
costs is $37.07 per MWh and capacity is $107.67 per kW-yr. Avista includes the savings
of future transmission and distribution expenses and line loss savings in both states'
avoided cost.
Figure 9.14: Washington Energy Efficiency Avoided Cost
Energy Value Capacity Value
$80 $140
$70 $120
.c: ... s: $60 >,
sec, I
~ $23.53 ~ $100 ~ ~ T&D, :;_ $50 ... $25.38 ~ $80 0 N
"'C a,
.!::!
cii > a,
..J
.c: s: ~ ~ ... >,
0 N
"C QI
.!::! cii > QI ..J
N $40 "'C a,
.!::! $60 cii $30 > a,
..J
$20 $40
$10 $20
$0 $0
Figure 9.15: Idaho Energy Efficiency Avoided Cost
$140
$120
$100
$80
$60
$40
$20
$0
Energy Value Capacity Value
. -· ..
Energy,
$34 87
... >, ~ ~ ~ ... >,
0 N
"C
QI .!::!
cii > QI ..J
$120
Losses, $5. 73
$100
T&D,
$25.38
$80
$60
$40
$20
$0
17 Washington's Energy Independence Act requires a 10% cost advantage adder for energy efficiency to
give this resource preference as required in the Northwest Power Act.
Avista Corp 2023 Electric IRP 9-29
Chapter 9: Preferred Resource Strategy
New Generation Avoided Costs
Avoided costs change as Avista's load and resource position changes, as well as with
changes in the wholesale power market and new resource costs. Avoided costs are a
best-available estimate at the time of this analysis. Specific project characteristics will
likely change the value of a resource. The prices shown in Table 9.7 represent energy
and capacity values for different periods and product types, including those providing
clean energy. For example, a new generation project with equal annual deliveries in all
hours has an energy value equal to the flat unspecified energy price shown in Table 9.7.18
In addition to the energy prices, these theoretical resources would also receive capacity
value for production at the time of system peak. This value begins in 2034.
Capacity value is the resulting average cost of capacity each year. Specifically, the
calculation compares a portfolio where the objective is to build resources to meet only
capacity requirements (excluding social cost of greenhouse gas) against a lower cost
portfolio with no resource additions.19 Avista uses these annual revenue requirement20
differences to create annualized costs of capacity beginning in the first year of a major
resource deficit. Recognizing cash flows fluctuate , the variability in annual values is
levelized and tilted using a 2% inflation rate. The next step divides the costs by added
capacity amounts during the winter peak. This value is the cost of capacity per MW or
cost per kW-year. The capacity payment applies to the capacity contribution of the
resource at the time of the winter peak hour.
New to this IRP is a second capacity value due to Washington requirements for a
transition to clean energy. In this case, a clean capacity premium is offered for capacity
reducing resources. Avista's greatest challenge in meeting the CETA targets is clean
capacity rather than clean energy as demonstrated by the need for storage and
renewable fueled CTs. The capacity premium was created by analyzing a portfolio with
only clean capacity resources being selected in a similar way to the traditional capacity
calculation discussed above. Due to cleaner resources having higher costs than natural
gas CTs there is a higher avoided cost of this capacity. Historically, Avista included this
cost within the clean energy premium , but has moved to a capacity value, as the capacity
is a greater constraint than energy in this IRP.
Capacity pricing at the full capacity payment shown in Table 9.11 assumes a 100% QCC
or Equivalent Load Carrying Capability (ELCC) in the winter. For example, solar receives
a 2% QCC credit based on ELCC analysis and would receive 2% of the capacity payment
compared with its nameplate capacity. Avista will need to either conduct an ELCC
analysis or utilize the QCC value from the WRAP for any specific project it evaluates to
determine its peak credit. The current forecast assumes Avista's capacity deficit is higher
in the winter than the summer for all future years of the planning horizon. However, a mild
18 Projects with undetermined energy production will need to be estimated based on the resource'
19 Descriptions of each of these portfolios are including in Chapter 10.
20 Transmission costs associated with new resources are included within the capacity cost. These include
the interconnection of the resource to the system and the cost to wheel power to Avista's customers.
Avista Corp 2023 Electric IRP 9-30
Chapter 9: Preferred Resource Strategy
winter and hotter than expected summer could result in an actual summer peak greater
than winter. Avoided costs are based on expected rather than actual costs.
VERs consume ancillary services because their output cannot be forecasted with great
precision. VERs seeking avoided cost pricing may receive reduced payments to
compensate for ancillary service costs if the resource is different than expected in the
PRS. The clean energy premium includes the VER cost as part of the estimated value.
The clean energy premium calculation is similar to the capacity credit but estimates the
cost to comply with CETA by comparing the PRS to the same portfolio used to calculate
the Clean Capacity Cost. Avista uses the annual revenue requirement differences to
create an annualized cost of clean energy beginning with the first year of clean energy
acquisition based on need for the resource (2034 )21 with an annual price adjustment of
2% per year. This new annual cost is divided by the incremental megawatt hours of
generation and the resulting value shows the amount of extra cost per MWh needed to
meet clean energy requirements. This benefit includes the cost associated with
transitioning to cleaner capacity resources, but also adding clean energy resources .
Clean energy premiums assume no change to renewable energy tax incentives but will
include any tax incentives if they are extended beyond the current Inflation Reduction Act
(IRA) amounts. The clean premium is significantly lower than the previous IRP due to
lower renewable costs, higher traditional energy costs, and creating the clean capacity
premium discussed above.
21 Avista's first selection of clean resource is prior to 2034 but is either due to the NCIF or taking advantage
of expiring IRA benefits.
Avista Corp 2023 Electric IRP 9-31
Chapter 9: Preferred Resource Strategy
Table 9.11: New Resource Avoided Costs
Flat Clean Clean Total Flat Total
Unspecified Unspecified Energy Capacity Clean Clean
Energy Capacity Premium Premium Energy Capacity
Year ($/MWh) ($/kW-Yr) ($/MWh) ($/kW-Yr) ($/MWh) ($/kW-Yr)
2024 $42.87 $0.0 $0.00 $0.0 $42.9 $0.0
2025 $35.87 $0.0 $0.00 $0.0 $35.9 $0.0
2026 $33.24 $0.0 $0.00 $0.0 $33.2 $0.0
2027 $29.89 $0.0 $0.00 $0.0 $29.9 $0.0
2028 $29.83 $0.0 $0.00 $0.0 $29.8 $0.0
2029 $29.93 $0.0 $0.00 $0.0 $29.9 $0.0
2030 $34.65 $0.0 $0.00 $0.0 $34.6 $0.0
2031 $32.57 $0.0 $0.00 $0.0 $32.6 $0.0
2032 $31.63 $0.0 $0.00 $0.0 $31 .6 $0.0
2033 $32.57 $0.0 $0.00 $0.0 $32.6 $0.0
2034 $33.11 $93.0 $2.86 $63.3 $36.0 $156.3
2035 $34.41 $94.8 $2.91 $64.6 $37.3 $159.5
2036 $35.06 $96.7 $2.97 $65.9 $38.0 $162.6
2037 $36.67 $98.7 $3.03 $67.2 $39.7 $165.9
2038 $36.37 $100.6 $3.09 $68.6 $39.5 $169.2
2039 $37.51 $102.7 $3.15 $69.9 $40.7 $172.6
2040 $39.50 $104.7 $3.22 $71 .3 $42.7 $176.1
2041 $39.70 $106.8 $3.28 $72.8 $43.0 $179.6
2042 $41.46 $108.9 $3.35 $74.2 $44.8 $183.2
2043 $42.40 $111 .1 $3.41 $75.7 $45.8 $186.8
2044 $47.58 $113.3 $3.48 $77.2 $51 .1 $190.6
2045 $47.48 $115.6 $3.55 $78.8 $51 .0 $194.4
20-year $35.46 $50.91 $1.56 $34.68 $37.03 $85.59 Levelized
22-year $36.56 $56.68 $1.74 $38.62 $38.30 $95.31 Levelized
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Chapter 10: Portfolio Scenario Analysis
10. Portfolio Scenario Analysis
The 2023 Preferred Resource Strategy (PRS) is Avista's resource strategy to meet future
load growth and replace aging generation resources through 2045. Because the future is
often different from the IRP's Expected Case forecast, the future resource strategy needs
flexibility to serve customers under a range of plausible outcomes. This IRP identifies
alternative optimized resource strategies for different underlying assumptions. 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.
Section Highlights
• All portfolios studied include greenhouse gas emission reductions.
• Moving to 100% clean energy will have significant rate impact to Idaho
customers toward the end of the plan.
• New and replacement natural gas peaking generation is cost effective for Idaho
customers even when considering social costs and potential national
greenhouse gas fees.
• The Western Resource Adequacy Program (WRAP) continues to provide small
financial benefits to Avista in exchange for a more reliable energy marketplace.
• Electrification of either transportation and/or buildings will require significant
amount of new generation, transmission, and distribution resources.
The portfolio scenarios are representative of studies requested by the Technical Advisory
Committee (TAC) or required by regulation. Avista also developed several scenarios of
based on potential future policies and ideas discussed at TAC meetings and the IRP
public meeting. In addition to alternative portfolio choices, Avista tested a few portfolios
under alternative market futures or sensitivities where resource choice differs from the
PRS. These sensitivities show how the portfolios perform with a national carbon tax and
with higher or lower natural gas prices.
Since Avista does not have significant resource needs until the 2030s, there is time to
watch for industry changes to see how the future evolves. The most significant risk
identified in this analysis is from higher load levels as a result of electrification of
transportation and/or space and water heating. These changes will likely occur at a
gradual enough pace to give the utility time to respond to electrification trends and not
shock the power supply system. However, the new load scenarios are large enough to
justify planning for long lead items as associated with transmission and distribution
system upgrades, or a new large industrial load may require new generation at a faster
pace.
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Chapter 10: Portfolio Scenario Analysis
Another risk identified in the scenario analysis occurs where Avista could change course
from the PRS due to a clean energy requirement in Idaho. While natural gas remains a
cost-effective option for Idaho customers, even when considering environmental costs;
technology or public policies changes could require a reduction of natural gas-fired
resources to serve Idaho customers. Based on the current political environment, this
would most likely come from a federal policy change or a significant cost reduction in non­
gas generation and storage from new technologies. Avista's customers, by way of survey
(TAC 4 presentation in Appendix A) shows a preference for renewable energy options
when the costs increases are manageable.
Portfolio Scenarios
In addition to the expected case, Avista studied 16 alternative portfolios to compare cost,
risk, and emissions with the PRS for the Expected Case market forecast. Each portfolio
changes an underlining assumption about the future and are then re-optimized to select
the lowest cost portfolio for the requirements of the scenario. The PRS is Portfolio #1 on
all tables and charts in this chapter. The summary of the resource selections for all
portfolio scenarios is in Table 10.1 and Table 10.2. Appendix K includes a summary of
resource selection by year by state for the expected case as well as each scenario
addressed below.
Portfolio #2: Alternative Lowest Reasonable Cost Portfolio
The Alternative Lowest Reasonable Cost Portfolio is a Washington State required
portfolio to determine whether a utility exceeds the Clean Energy Transformation Act
(CETA) cost cap if the utility is using the method for compliance. This portfolio assumes
no CETA clean energy requirements, nor does it include any Named Community
Investment Fund (NCIF) investments but does include the Social Cost of Greenhouse
Gas (SCGHG) for resource selection and continues to meet physical monthly capacity
and energy requirements.
The study shows lower costs for Washington by $7.8 million per year levelized, while
Idaho's cost changes are de minimis. The portfolio cost toward the end of the study
horizon is $81 million lower in 2045 or 5% less cost per kWh . The reduction in cost is
largely due to this portfolio continuing use of Coyote Springs 2 in 2045 for Washington
customers, but results in fewer renewables (including renewable fueled Combustion
Turbines (CTs)) and more long-duration storage and natural gas CTs.
Portfolio #3: Baseline Portfolio
This scenario represents resource choices based on the economic decisions without the
SCGHG or CETA. Effectively this portfolio uses the same assumptions as Portfolio #2 but
exclude SCGHG prices for Washington. This portfolio is important for developing the
Avoided Costs discussed in Chapter 9 as it can separate portfolio costs by renewable
and capacity premiums. This portfolio methodology (for the Washington portion) is similar
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to Idaho's assumptions for new resource selection, with non-energy impacts (NEis) still
included for Washington resource optimization.
By comparing the results of this portfolio with Portfolio #2, the impacts of the SCGHG
assumption on resource selection can be quantified. In this portfolio, the amount of wind
selected falls by nearly 600 MW for Washington and future resource needs are satisfied
with natural gas turbines and energy storage. One curious modeling result is the selection
of wind, additional storage, and demand response, while reducing the amount of natural
gas CTs for the Idaho jurisdiction. This is likely a result of limited low-cost transmission,
lowest cost resources spread between each jurisdiction and more resources selected as
system resources rather than state specific.
As expected, this portfolio has a lower cost than the PRS and the Alternative Lowest
Reasonable Cost portfolio. In this case, Washington costs are $13 million lower
(levelized) and $203 million lower by 2045 (13% less per kWh) as compared to the PRS.
For Idaho, costs changes compared to the PRS are again de minimis.
This portfolio is compared to Portfolio #4 for capacity avoided cost purposes resulting in
$173.3 million Present Value of Revenue Requirement (PVRR) of additional cost to the
system. When divided by the added capacity this creates a capacity cost of $93 per kW­
year in 2034 with a 2% escalator for the lowest cost resource set to meet capacity needs.
This portfolio can also be used to estimate the clean energy premium by comparing the
PVRR to the PRS. The PRS includes a $16 million PVRR premium. Dividing this
additional cost by the added energy results in a $3.80 per MWh clean energy benefit
beginning in 2034 with a 2% per year escalator (see Chapter 9 for more information on
Avoided Cost).
Portfolio #4: No Resource Additions
This portfolio is used to estimate the capacity premium for the Avoided Cost calculation.
The portfolio does not include any resource additions other than it uses the same energy
efficiency selections as the PRS. It also includes the same assumptions as the #3
Baseline Portfolio with the exception of using the market to meet all resource demands
instead of acquiring additional resources. The costs are lower for this scenario as no new
resources are required, but it is not a valid portfolio for cost comparisons other than for
use in Avoided Cost calculations.
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Table 10.1: Resource Selection Summary by Portfolio Scenario in MW (Washington)
Storage Other Existing EE-
Added to Hydrogen/ "Clean" Plant DR EE-Winter Summer
Portfolio Scenario NGCT Solar Solar Wind Storage .Ammonia Baseload Upgrades Capability Capacity Capacity
1-Preferred Resource Strategy 0 10 0 945 130 696 0 0 7 57 59
2-Alternative Lowest Reasonable Cost Portfolio 247 51 25 843 494 88 0 0 7 57 60
3-Baseline Portfolio 431 0 0 364 265 0 0 3 7 57 59
4-No Resource Additions 0 0 0 0 0 0 0 0 0 57 59
5-No CETN No new NG 0 0 0 400 795 79 0 0 7 55 59
6-WRP.P PRM 0 11 1 1,028 365 578 20 6 7 57 60
7-WRP.P PRM No ace Chanoes 0 11 0 1,145 454 312 78 6 7 57 59
8-VERs Assigned to Washinaton 0 11 0 845 125 682 20 0 7 57 59
9-low Economic Growth Loads 0 10 1 905 298 366 98 3 7 57 59
10. High Economic Growth Loads 0 11 1 1,045 209 646 20 3 7 57 59
11-High Electric Vehicle Growth 0 97 0 1,245 492 707 98 0 7 57 59
12-WA Space/ Water Electrification 0 11 0 1,545 935 890 98 0 7 57 60
13-WA Space/ Water Electrification w/NG Backup 0 161 1 1,345 569 767 98 0 7 57 60
14-Combined Electrification 0 11 0 1,545 1,231 712 447 3 7 58 60
15-Clean Portfolio bv 2045 0 10 1 1,009 91 704 33 0 7 57 59
16-Social Cost Included for Idaho 0 84 37 905 123 682 20 0 7 57 59
17-WA Maximum Customer Benefits 0 827 1 845 591 228 40 3 7 58 60
Table 10.2: Resource Selection Summary by Portfolio Scenario in MW (Idaho)
Storage Other EXJsting EE-
Pddedto Hydrogen/ "Clean" Plant OR EE-Winter Summer
Portfolio Scenario NGCT Solar Solar Wind Storage Ammonia Baseload Upgrades Capab1hty Capacity Capacity
1-Preferred Resource Strategy 304 0 0 0 67 0 0 0 0 24 24
2-Alternative Lowest Reasonable Cost Portfolio 264 0 0 0 89 0 0 0 0 25 26
3-Baseline Portfolio 164 0 0 36 176 0 0 2 11 24 24
4-No Resource Additions 0 0 0 0 0 0 0 0 0 24 24
5-No CETN No new NG 0 0 0 0 350 0 0 0 0 22 21
6-WRP.P PRM 302 0 0 0 87 0 0 4 0 24 26
7-WRP.P PRM No ace Changes 278 0 0 0 126 0 0 4 5 24 26
8-VERs Assianecl to Washinaton 318 0 0 0 42 0 0 0 0 24 24
9-Low Economic Growth Loads 229 0 0 0 n 0 0 2 0 24 24
10-HiQh Economic Growth Loads 349 0 0 0 112 0 0 2 7 24 24
11-High Electric Vehicle Growth 293 0 0 0 161 0 0 0 0 24 25
12-WASpace/ Water Electrification 267 0 0 0 135 0 0 0 0 24 24
13-WA Space/ Water Electrification w/NG Backup 272 0 0 0 149 0 0 0 0 26 25
14-Combined Electrification 283 0 0 0 167 0 0 2 0 26 26
15-Clean Portfolio by 2045 0 0 0 236 18 3TT 65 0 7 27 28
1~ Social Cost Included for Idaho 203 0 0 0 36 115 20 0 0 24 26
17-WA Maximum Customer Benefits 271 0 0 0 85 0 0 2 0 24 24
Portfolio #5: No CETA/ No New Natural Gas
This portfolio identifies the clean capacity premium avoided costs. It is similar to the #2
Baseline Portfolio, except it does not allow new natural gas generation to be constructed,
does not require the model to satisfy monthly energy targets and assumes Coyote
Springs 2 is not available in Washington in 2045. This illustrates a portfolio without the
specific CETA objectives but nearly eliminates greenhouse gas emitting resources by
2045. This portfolio does not meet general utility planning requirements as the utility is
significantly short energy on an annual basis beginning in 2042. Given this portfolio is for
avoided cost purposes only, the results should only be used in this context, a separate
portfolio for achieving higher clean energy objectives is discussed later.
The resource selection in this scenario chooses long-duration energy storage over
renewable fuel and natural gas CTs, these changes result in reduced amounts of wind
generation. The reason for the significant resource selection changes compared to the
PRS is due to the CETA requirements with primary versus alternative compliance and the
monthly energy requirement being removed. Idaho sees significant resource decision
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changes in this portfolio as it no longer has natural gas CTs as a resource choice. As the
model is not requiring energy goals to be satisfied, the natural gas CTs are exchanged
for energy storage resources.
This portfolio is only used for Clean Capacity Avoided Cost purposes by comparing the
cost and resource selection with the #4 No Additions Portfolio. The increase in total costs
is approximately $300 million. When levelized against the added capacity, it results in a
$156 per kW-year capacity premium with a 2% escalator. However, a $93 per kW-year
could be associated with non-clean energy by comparing the #3 Baseline Portfolio to the
#4 No Additions Portfolio, therefore the difference between these two values is the clean
capacity premium of $63 per kW-year.
Portfolio #6: WRAP Planning Reserve Margins (PRM)
This portfolio scenario shows how the PRS might change once it adopts the Western
Power Pool's WRAP's Planning Reserve Margin (PRM). Avista has chosen to use the
WRAP's Qualifying Capacity Credit (QCC) values and Load and Resources (L&R)
calculation methodology to determine resource need in this IRP but does not plan to
implement lower PRM values until the program is fully binding. Table 10.3 compares the
WRAP's PRM 1 values to those of the PRS, except for the shoulder month values in March
through May and September, the PRM values are lower.
Table 10.3: Resource Selection Summary by Portfolio Scenario
Month WRAP 2023 IRP
Jan 19.0% 22.0%
Feb 19.9% 22.0%
Mar 26.9% 22.0%
Apr 23.4% 22.0%
May 20.0% 13.0%
Jun 16.5% 13.0%
Jul 10.4% 13.0%
AUQ 10.3% 13.0%
Sep 17.9% 13.0%
Oct 19.8% 22.0%
Nov 21 .6% 22.0%
Dec 17.7% 22.0%
An interesting result of this portfolio scenario is the resource selection is not lower, and
resource selection changed due to the seasonal differences in resource need. The model
generally selected the same amount of natural gas CTs for Idaho, but Washington
selection shifted from renewable fuel CTs to long duration storage, additional wind , and
baseload renewables along with upgrading the existing Rathdrum CTs.
1 The PRM values within the WRAP use the 2023 forward showing values and are subject to change.
WRAP does not estimate PRM for shoulder months, they are estimated in this chart based on connecting
months.
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In the 2021 IRP, the WRAP scenario showed a cost savings to both Idaho and
Washington. One of the reasons the model does not find as much savings as the 2021
IRP is due to binding constraints to meet monthly energy requirements. In the 2021 IRP,
these constraints only had to be met on an annual average basis. While the savings in
this IRP are not as high in the 2021 IRP, the WRAP is still an important market
development to ensure the region is resource adequate and allows Avista to use the
market during extreme peak conditions and discourages other utilities from being overly
reliant on market resources to meet peak demand.
Portfolio #7: WRAP PRM (No QCC Changes)
The WRAP creates QCC estimates used to determine how much an individual resource
can be relied upon for winter and summer peak loads. Avista assumes these values will
go down over the course of the study2 for variable energy resources (VERs), storage
resources, and demand response. This is due to the energy limitations of the resources
and the inability to serve customer load for a duration of time and the high correlation of
generation availability. For this IRP, Avista modified these QCC values based on a
regional clean energy study from E3 (discussed in prior chapters). This portfolio scenario
was developed to address TAC members concerns with the WRAP PRM assumptions as
the WRAP has not yet conducted studies on these resources maintaining their QCCs with
higher regional renewable and storage penetrations. This scenario uses the same WRAP
planning margins as Portfolio #6, but the QCC values do not change over the time horizon
of the study.
Higher peak generation capability or QCCs for renewable, storage, and demand response
resources create a different resource strategy. For Washington, wind energy increases,
and 4-hour energy storage replaces renewable fuel CTs needed for sustained high loads.
Another significant change is the selection of baseload renewables such as geothermal
and wood biomass. For the Idaho resource selection, the natural gas CT selection is
slightly lower in favor of 4-hour duration energy storage and some limited demand
response.
These assumption changes would effectively require the utility to rely more on the
wholesale energy market for its energy needs than the PRS does for peak load periods.
In exchange, it reduces cost as compared to the PRS, the PVRR is $106 million less or
$9.2 million per year. Most of the total savings occurs after 2034 when Avista is short
capacity. Since the resource strategy prior to 2034 is similar to the PRS, this period will
allow time for further studies by the WRAP and other regional entities to determine how
QCCs may change over the planning horizon.
2 Southwest Power Pool (SPP), who administers the WRAP, acknowledges the QCCs will decline as more
renewables are added to the system. They're in the process of conducting a study to quantify the impact of
these increasing amounts of VER.
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Portfolio #8: Variable Energy Resources Assigned to Washington
This portfolio uses the PRS's assumptions with one minor change, this change assigns
all existing VERs to Washington rather than between states. The VERs include Palouse
Wind, Rattlesnake Flat, and the new 30-year wind Purchase Power Agreement (PPA).
This change allows energy produced from these facilities to be used for CETA without a
transfer of the energy between states. The PRiSM model does allow these resources to
be transferred within the PRS, but it may not, depending on the timing and cost of
resource alternatives.
The goal of this study is to determine the amount and cost of new renewable generation
avoided. This concept is similar to conditions in Washington's Clean Energy
Implementation Plan (CEIP) to understand resource selection of new versus existing
resources. Unfortunately, the PRiSM model was not designed to separate specific
existing Power Purchase Agreement (PPA) resource costs between jurisdictions. This
was a design choice in PRiSM to avoid specific resource price transparency due to the
confidentially of PPA prices within agreements.
This study found Washington could reduce its renewable resource need by 100 MW of
wind and minor changes in other resource selections. The results show the total system
PVRR did increase by $29 million or 0.2%. Although this is likely due to a different set of
resources selected to meet different capacity/energy deficits than the PRS. This portfolio
should be studied in further detail in a future jurisdictional allocation conference setting if
the states agree to discuss resource cost allocations.
Portfolio #9: Low Economic Growth Loads
This portfolio studies the effects of loads not materializing as forecasted due to low
economic growth. A full description of the load scenario is in Chapter 2, but in this case,
load grows at 0.53% instead of 0.85%. The load reduction impacts Idaho and Washington
loads. As anticipated with lower loads, the resource strategy includes less wind, natural
gas CTs, and renewable fueled CTs. Although the amount of storage and baseload
renewables increases for both states.
The portfolio cost for both jurisdictions is lower, although disproportionately less for Idaho
(-1.8% versus -0.9%). One interesting note, with less load and lower cost, the rate per
kWh increases for both states. Absent non-power supply costs increasing, higher loads
can reduce the average rate as it can dilute fixed costs for customers.
Portfolio #10: High Economic Growth Loads
This portfolio considers the effects to the resource portfolio if loads are higher than
forecasted due to high economic growth. A full description of the high load scenario is in
Chapter 2, but in this case, load grows at 1.11 % instead of 0.85%. The load increase
impacts both Idaho and Washington loads.
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The higher loads results in more generation required than expected . Washington needs
additional renewables and energy storage, and Idaho needs additional Natural Gas CTs,
energy storage and demand response.
As with the low load growth scenario, the costs change as expected, but Idaho is impacted
more than Washington, where its cost increase at 1.8% compared to 0. 7% for
Washington. Also, the average rate per kWh decreases due to higher loads absent fixed
costs increasing to support the higher load.
Portfolio #11: High Electric Vehicle Growth
This is the first of several electrification scenarios studied in this IRP. Washington and
Idaho loads increase in this scenario due to the electrification of more transportation than
assumed in the PRS. Chapter 2 describes the specific load changes for both states, but
generally this scenario assumes a more rapid accumulation of light duty vehicles (LDVs)
and medium duty vehicles (MDVs) reflecting 100% LDV sales in Washington by 2050 and
75% for Idaho. For MDVs the assumption is for 95% by 2050 for Washington and 75%
for Idaho. By 2045, this results in an additional 193 aMW of energy demand and peak
loads increasing by 435 MW (20% higher than 2045 expected loads).
Due to higher loads, resource selection changes for both states. For Washington , PRS
resource selections are higher with 300 MW more wind, 87 MW solar, 363 MW of energy
storage, 98 MW baseload renewables and 10 MW of renewable fueled CTs. The change
in Idaho is slightly less natural gas (-10 MW) and additional energy storage (+94 MW).
This portfolio results in two additional transmission projects than the PRS with new
transmission needed from 2044 to 2045 for new wind and import capability.
The increase in load has a greater effect on Washington costs than Idaho. Washington
PVRR cost increases by 3.2% and Idaho 0.6%, but the Washington rates decline from a
cost per kWh perspective. This does not include added costs to integrate this load on the
distribution or transmission system. Avista hopes to estimate transmission and
distribution (T&D) costs in the future. This will be discussed in future Distribution Planning
Advisory Group (DPAG) meetings.
Portfolio #12: Washington Space/Water Heating Electrification
This portfolio scenario focuses on Washington building electrification, specifically if
existing customers change their current natural gas fired appliances (space and water
heating) to electric heat pumps with back up resistance heating and heat pump water
heaters. This scenario's load assumptions are described in Chapter 2. In summary,
average annual loads increase by 208 aMW by 2045, but winter peak loads increase 805
MW (winter is 36% higher) and summer by 91 MW. This scenario creates significant load
pressure on winter loads as moving the existing gas customers to electric will create
significant peak winter loads due to resistance space heating loads. In addition , the
current heat pump technology is limited in its ability to produce enough heat to satisfy
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building demand in extreme cold weather as seen in eastern Washington during peak
load events.
The added load in Washington is served by an additional 600 MW wind , 805 MW energy
storage, 194 MW renewable fueled CTs, and 98 MW base load renewable energy. Idaho
sees small changes to its portfolio even though its load remains unchanged. These
changes include 82 MW of energy storage and 32 MW fewer natural gas CTs and are
largely due to changes in the shared resources selected in the PRS. This portfolio
requires at least four large transmission projects to bring the new resources to serve load.
The first must be online by 2036 and the other three between 2042 and 2044. The
transmission would bring power from potential north Idaho plant locations to Spokane,
integrate new wind in eastern Washington, and import power from outside of Avista's
service area.
Washington costs and rates will increase significantly for this type of electrification as
PVRR is 10.5% higher and the 2045 energy rates are 11 % higher. These increases will
be higher once transmission and distribution costs are factored into the analysis. Idaho's
costs increase by 1.2% for PVRR and 5.7% for energy rates in 2045 . In this case, Idaho's
cost increases are mostly driven by how new transmission costs are allocated rather than
resource changes. This scenario requires significant transmission to integrate the new
resources for Washington, under the current cost recovery methodology, 34% of these
costs would be directed to Idaho to pay its share of the costs as new transmission is a
system benefit. If these costs were re-directed to Washington , Idaho would not see a rate
impact and Washington's 2045 rate would be 13% higher.
Portfolio #13: WA Space/Water Heating Electrification w/ Natural Gas Backup
Due to the high load requirements and costs of Portfolio #12, this scenario reduces the
winter peak load increase by using natural gas as a backup fuel. In this scenario, existing
customers would not replace their natural gas furnace over time, but rather add a heat
pump and use it for heating when temperatures are above 40-degrees. This scenario also
assumes natural gas water heaters are replaced with electric water heater heat pumps.
The result of these future load assumptions is an increase in annual energy loads by 152
aMW, but only 445 MW of winter peak load (compared to 805 MW in Portfolio #12-for a
total of 20% higher loads than the 2045 expected case value), and summer peak loads
are nearly the same as Portfolio #12.
This scenario still requires more resources than the PRS, but significantly less generation
than Portfolio #12. In this case, 600 MW less wind, energy storage, and renewable fueled
CTs are required compared to Portfolio #12, but 151 MW of solar is also selected. For
Idaho, similar changes are made to the resource strategy as Portfolio #12. This portfolio
results in two additional transmission projects in 2044 to 2045 for new wind and import
capability.
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With less load, the financial impacts to Washington customers are not as great as portfolio
#12, as PVRR increases $574 million (5.6%) compared to the PRS and rates only are
4.1 % higher in 2045. Though this scenario has similar impacts to Idaho rates as Portfolio
#12 , where Idaho rates are 5.1% higher in 2045.
Portfolio #14: Combined Electrification
This portfolio represents the extreme load growth scenario of what could be possible with
all electrification policy choices in Washington State materializing by 2045. In this
scenario the, High EV forecast from Portfolio #11 combines with the building electrification
of Portfolio #12, plus an increase in roof top solar to offset some of this new load with
20% of residential customers and 5% of commercial customers having roof top solar by
2045. The net effect increases annual energy load by 345 aMW, winter peaks by 1,224
MW (55% higher) and summer peaks by 316 MW by 2045.
The increased load requires an additional 600 MW of wind, 1,100 MW of long-term energy
storage, 58 MW of wood biomass, and 350 MW of nuclear capacity by 2045. In addition
to these resources , transmission to interconnect these resources will need to be
constructed with the first major project on-line by 2037 and three other major projects by
2045 subject to final generation location selection.
The cost increase to serve this additional load increases Washington's PVRR by 14%
and its 2045 energy rate by 16.5% or 4 cents per kWh. If Washington must pay for the
entire transmission costs as described in Portfolio #12 costs will increase even more. This
scenario will also see additional costs to integrate the higher loads on the distribution
system that are not factored into this cost estimate. Although early estimates (subject to
change as discussed in Chapter 7) places this cost at $2.5 billion (total nominal dollars)
of capital investment through 2045. This translates into an additional 4 cents per kWh of
added load. The end result is a 33% higher average energy rate for Washington
customers in this scenario versus the PRS. For Idaho, cost impacts have not been
estimated, but are likely to be minimal.
Portfolio #15: Clean Portfolio by 2045
The Clean Portfolio would not have any greenhouse gas emitting resources after 2044.
This includes retiring all existing natural gas generation by 2045 (including Coyote
Springs 2) and not acquiring any additional gas facilities. This scenario has little impact
on Washington as it is already required under CETA's policy goals. Although, Washington
will not have the ability to use Idaho's share of clean resources to the extent it may require,
and it will have to procure additional higher cost renewables to comply with the larger
system-wide clean goal.
The portfolio changes in this scenario in Washington to include wind (+64 MW), energy
storage (-39 MW), and baseload renewables ( +33 MW). Idaho's portfolio is significantly
different with 303 MW fewer natural gas CTs plus 236 MW of new wind and 378 MW of
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renewable fueled CTs along with a shift from energy storage to wood biomass from the
PRS. Additional transmission is also required for this portfolio as compared to the PRS.
Transmission projects to integrate eastern Washington wind and import off system
resources would need to be available by 2044 in addition to the transmission required to
bring capacity from North Idaho to the Spokane area.
For cost impacts, Washington sees marginal increases in PVRR of 0.1 % and the 2045
energy rates are 2.6% higher. Idaho's cost impacts are far higher. The PVRR is only 2.5%
higher, but the significant costs materialize toward the end of the plan where the 2045
energy rate is 40% higher or 7.4 cents per kWh. In this scenario, Washington has a 2045
energy rate of 24 cents per kWh and Idaho 25 .9 cents per kWh. The Washington rate is
slightly lower due to higher loads. Although, in this scenario the Production Transmission
{PT) ratio (used to allocated cost to each jurisdiction) would likely change and the rates
between the two states would likely land in between these two rate forecasts.
Portfolio #16: Social Cost Included for Idaho
The scenario attempts to include the non-energy impacts (NEI) of resource decisions into
the resource selection process for Idaho. Specifically, this concept was suggested in the
2023 IRP public meeting process to understand whether the selection of natural gas
turbines for Idaho can overcome these costs. In this scenario, the SCGHG and NEis used
for Washington's resource selection are used in Idaho. This portfolio shows what
resources are truly economic when accounting for externalities and demonstrates the
premium 100% clean energy policies may have exceeded what is actually economic even
when considering social impacts.
This scenario repositions both states resource selections. Washington has a 74 MW
increase in solar, 37 MW of energy storage, and 20 MW of geothermal, while wind, long­
duration energy storage, and renewable fueled CTs fall. For Idaho, there is a 100 MW
reduction in natural gas peakers replaced by a 116 MW renewable fueled CT. There is
also a reduction in energy storage, replaced by a 20 MW geothermal unit. Another
interesting impact of this scenario is the model generally prefers shared resources for
energy storage and renewable fueled CTs. This portfolio does not require additional
transmission beyond what is needed in the PRS.
The cost impacts to the system portfolio cost are minimal, Washington has only de
minimis cost effects, but Idaho's PVRR increases by 0.4% and the 2045 rates only 1.8%.
An important note is the premium Washington customers will pay for 100% clean energy
over the economic value of the alternative choices. Washington's 2045 energy rate is
23.5 cents per kWh and Idaho's would be 18.8 cents per kWh. Given this, Washington
would be paying a 25% premium over the social value of clean energy it is producing.
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Portfolio #17: Washington Maximum Customer Benefits
The Washington State IRP rules require a Maximum Customer Benefits portfolio to
understand the portfolio and cost impacts of additional Customer Benefit Indicators
(CBls). The portfolio is designed to take another step beyond the 2021 IRP to define what
this portfolio future may look like. There are no specific rules guiding this portfolio but
rather a set of assumptions to see how CBls may improve. Avista expects to have more
discussion with the TAC in the 2025 IRP cycle to refine this portfolio's assumptions.
For this IRP, the following assumptions based on the current CBls were used. The model
would not be able to select any renewable energy outside of the state (i.e., Montana
Wind). 3 This increases the quantity of local generation CBI. The model cannot select
renewable fueled CTs (i.e., ammonia turbines) due to additional NOx emissions, but can
use hydrogen fuel cells. The amount of community solar increases beginning in 2034 for
the benefit of Named Communities to lower the burden to low-income customers (solar
selected directly offsets customer bills). No nuclear energy was allowed to be constructed .
While this was not a CBI; it was added from TAC input on this scenario in the 2021 IRP.
These scenario assumptions add 817 MW of solar energy with 676 MW of the amount
directly benefiting low-income customers. Since the model cannot select ammonia-fueled
turbines, the resource selection uses green hydrogen fuel cells, energy storage, and
geothermal to meet the remaining capacity requirements after the significant increase in
solar energy. Idaho's portfolio is only modestly impacted . Due to the changes in resource
selection, additional large transmission projects are still needed, but changes the specific
transmission needs to only support new wind generation on and off the system, as long
as the majority of the 676 MW of solar added to the system does not create
transmission/distribution impacts. Avista's Distributed Energy Resource (DER) potential
study for the 2025 IRP will determine if this amount of solar on a local level is possible.
There are cost impacts to Washington customers for these portfolio changes. The PVRR
increases 3.7% and the 2045 energy rate increases 29% or 6.8 cents per kWh. In
exchange for the higher rate, there are less air emissions (except those related to Kettle
Falls Generating Station). The average excess energy burden of low-income customers
falls from $2,035 per year in 2045 to $632 per year. DER MWh increase to 1 million MWh
per year compared to 34,000 MWh and energy storage in Named Communities increase
to 60 MWh compared to 12 MWh in the PRS.
Cost & Rate Impact Summary
The preceding portfolio summary gave contextual changes to each portfolio. This section
provides tables and charts to summarize the results of the studies. Table 10.4 outlines
each of the 17 portfolio PVRRs for each state, and the 2030 and 2045 energy rates per
3 The PRiSM model is not designed to select the location of wind resources other than off-system , on­
system or from Montana. For this study, off-system wind can still be selected as the northwest location is
unknown.
Avista Corp 2023 Electric IRP 10-12
Chapter 10: Portfolio Scenario Analysis
kWh (excludes distribution adders discussed in the electrification scenarios). The yellow
bars show the cost or rate of the category is within 3% of the PRS value, the green arrow
up indicates the category exceeds a 3% increase compared to the PRS, and the red arrow
down indicates a 3% reduction.
The costs of each portfolio are summarized by jurisdiction and are then sorted by total
system cost impact in Figure 10.1. The higher cost scenarios include higher loads or
higher clean energy objectives, while lower cost scenarios have less loads or renewables.
Though the rank order does not reflect the additional load served by these scenarios,
therefore Figures 10.2 and 10.3 show the rank of the energy rates for 2030 and 2045,
sorted by 2045 rates. The 2030 rates do not materially differ since most resource
decisions occurring after 2030.
Table 10.4: Jurisdiction Cost and Rate Summary
Scenario WA-PVRR ID-PVRR ($ TOTAL WA 2030 WA 2045 ID 2030 ID 2045
($Mill) Mill) PVRR ($ Rate Rate Rate Rate
Mill) ($/kWh) ($/kWh) ($/kWh) ($/kWh)
1-Preferred Resource Strategy = 10,213 = 4,783 = 14,996 = 0.133 = 0.234 = 0.119 = 0.185
2-Alternath.e Lowest Reasonable Cost Portfolio = 10,122 = 4,778 = 14,900 = 0.132 • 0.222 = 0.119 = 0.181
3-Baseline Portfolio = 10,064 = 4,789 = 14,852 = 0.133 • 0.205 = 0.119 = 0.184
4-No Resource Additions = 9,966 = 4,713 = 14,679 = 0.133 • 0.194 = 0.119 ... 0.169
5-No CETA/ No new NG = 10,158 = 4,821 = 14,980 = 0.133 • 0.223 = 0.119 = 0.188
6-WRAP PRM = 10,217 = 4,778 = 14,995 = 0.133 A 0.242 = 0.119 = 0.186
7-WRAP PRM No QCC Changes = 10,126 = 4,763 = 14,889 = 0.133 = 0.233 = 0.119 = 0.179
8-VERs Assigned to Washington = 10,205 = 4,819 = 15,024 = 0.133 = 0.234 = 0.120 = 0.184
9-Low Economic Growth Loads = 10,119 = 4,697 = 14,816 = 0.134 ... 0.243 = 0.120 I.a 0.192
10-High Economic Growth Loads = 10,279 = 4,868 = 15,148 = 0.132 = 0.233 = 0.117 ... 0.176
11-High Electric Vehicle Growth ... 10,541 = 4,812 = 15,354 = 0.133 = 0.227 = 0.119 = 0.186
12-WA Space/ Water Electrification A 11,283 = 4,843 A 16,126 = 0.131 ... 0.259 = 0.119 ... 0.195
13-WA Space/ Water Electrification w/NG Backup A 10,787 = 4,800 A 15,586 = 0.132 ... 0.244 = 0.119 A 0.194
14-Combined Electrification A 11,655 = 4,879 .... 16,533 = 0.131 ... 0.273 = 0.119 ... 0.195
15-Clean Portfolio by 2045 = 10,227 = 4,902 = 15,130 = 0.133 = 0.240 = 0.119 ... 0.259
16-Social Cost Included for Idaho = 10,219 = 4,801 = 15,021 = 0.133 = 0.235 = 0.118 = 0.188
17-WA Maximum Customer Benefits 6 10,594 = 4,769 = 15,363 = 0.134 A 0.302 = 0.119 = 0.182
Avista Corp 2023 Electric IRP 10-13
Chapter 10: Portfolio Scenario Analysis
Figure 10.1: PVRR Summary
14-Combined Electrification $11,655 $16,533
12-WA Space/ Water Electrification $11 ,283
13-WA Space/ Water Electrification w/NG Backup $10,787 $4,800
17-WA Maximum Customer Benefits $10,594 $4,769
11-High Electric Vehicle Growth $10,541 $4,812
10-High Economic Growth Loads $10,279 $4,868
15-Clean Portfolio by 2045 $10,227 $4,902
8-VERs Assigned to Washington $10,205 $4,819
16-Social Cost Included for Idaho $10,219 $4,801
1-Preferred Resource Strategy $10,213 $4,783
6-WRAP PRM $10,217 $4,778
5-No CETA/ No new NG $10,158 $4,821
2-Alternative Lowest Reasonable Cost Portfolio $10,122 $4,778
7-WRAP PRM No QCC Changes $10,126 $4,763
3-Baseline Portfolio $10,064 $4,789
9-Low Economic Growth Loads $10,119 $4,697
4-No Resource Additions $9,966 $4,713
0 0 0 0 0 0 0 0 0 0 0 tF> 0 0 0 0 0 0 0 0 0 0 0 o_ 0 0 o _ o_ o_ o _ o_ o _ N '<I" c.o a5 0 N '<I" CD co 0 tF> tF> tF> tF> ~ ~ ~ ~ ~ N tF> tF> tF> tF> tF> tF>
WA-PVRR ($ Mill) ■ID-PVRR ($ Mill) TOTAL PVRR ($ Mill)
Avista Corp 2023 Electric IRP 10-14
Chapter 10: Portfolio Scenario Analysis
Figure 10.2: Washington Energy Rate Comparison
17-WA Maximum Customer Benefits
14-Combined Electrification
12-WA Space/ Water Electrification
13-WA Space/ Water Electrification w/NG Backup
9-Low Economic Growth Loads
6-WRAP PRM
15-Clean Portfolio by 2045
16-Social Cost Included for Idaho
1-Preferred Resource Strategy
8-VERs Assigned to Washington
?-WRAP PRM No QCC Changes
10-High Economic Growth Loads
11-High Electric Vehicle Growth
5-No CETA/ No new NG
2-Alternative Lowest Reasonable Cost Portfolio
3-Baseline Portfolio
4-No Resource Additions
0.134
0.131
0.131
0.132
0.134
0.133
0.133
0.133
0.133
0.133
0.133
0.132
0.133
0.133
0.132
0.133
0.133
0.302
0.273
0.259
0.244
0.243
0.242
0.240
0.235
0.234
0.234
0.233
0.233
0.227
0.223
0.222
0.205
0.194
$0.00 $0.05 $0. 10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40
■ WA 2045 Rate ($/kWh) ■ WA 2030 Rate ($/kWh)
Figure 10.3: Idaho Energy Rate Comparison
15-Clean Portfolio by 2045
14-Combined Electrification
12-WA Space/ Water Electrification
13-WA Space/ Water Electrification w/NG Backup
9-Low Economic Growth Loads
5-No CETA/ No new NG
16-Social Cost Included for Idaho
11-High Electric Vehicle Growth
6-WRAP PRM
1-Preferred Resource Strategy
3-Baseline Portfolio
8-VERs Assigned to Washington
17-WA Maximum Customer Benefits
2-Alternative Lowest Reasonable Cost Portfolio
7-WRAP PRM No QCC Changes
10-High Economic Growth Loads
4-No Resource Additions
0.119
------0.195 ------0119 --
------0.195 ----b 119 --
------0.194 -----o:11e·--
------0.192 -----0:T~
-----0.188
-----0.119
-----0.188 -----E11s ___ _
----0.186 ~
----0.186 -----0.119 _____ _
----0.185 -----0119 ---
----0.184 ------6Ti9 -
----o.184 -----0120 ---
------0.182 -----0.119 ··
------0.181 -----0119 -
-----0.179
-----0.119
------0.176 -0.117
0.169
0.259
$0.00 $0.05 $0. 10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40
■ ID 2045 Rate ($/kWh) ■ ID 2030 Rate ($/kWh)
Avista Corp 2023 Electric IRP 10-15
Chapter 10: Portfolio Scenario Analysis
Market Risk Analysis
In addition to costs or energy rates, the IRP gives insights to the energy market risks of
portfolios by showing how much the portfolio selection is impacted by changes in the
wholesale electric market. Figure 10 .4 compares the 2045 market risk to the PVRR of the
portfolio cost (excludes additional distribution costs for electrification scenarios). The
2045 market risk used in this analysis is TaiIVar95 and calculated by the 95th percentile
of portfolio costs subtracting the average portfolio cost for 300 simulations. The market
risks included are from varying loads, natural gas prices, hydro conditions, and wind
conditions. The portfolios with greater risk typically have a higher dependance on either
natural gas resources, market power purchases, or higher risk due to added load.
The only portfolios to further reduce market risk for the Idaho jurisdiction are those
investing in additional renewable energy resources. As shown below, the lower risk
comes at an added cost to the system. For example, in the #15 Clean Portfolio by 2045
scenario, the extreme market risk is $23 million or 28% lower, but the incremental cost to
Idaho customers in 2045 is $267 million, reflecting a $0.075 per kWh premium or 40%
higher. There is a point where additional cost can be justified by the risk savings, but this
scenario may not justify the cost premium. The #16 Social Cost Included in Idaho Portfolio
has a $5 million risk reduction at an $11 million premium. In this case, the social cost
benefits would offset the difference in cost, but Avista will need guidance from the Idaho
Public Utilities Commission (IPUC) if these social benefits are the correct valuation for
Idaho customers.
ll) en ...
('Cl >
"iii
I-
ll)
'<t 0 N
Avista Corp
$160
$140
$120
$100
$80
$60
$40
$20
Figure 10.4: System Cost versus Risk Comparison
4-No Resource
[ Additions 13-WA Space/ Water
5-No CETA/ No new I Electrification w/NG
Backup
.__ 14-Combined
Electrification NG
3-Baseline Portfolio /
12-WA Space/ Water
•---Electrification 2-Alternat 11-High Electric Vehicle r 17-WA Maximum
Q Customer Benefits Reasonable Cost ~ e-.fb====G=ro=wt=h==~~;;~ Portfolio 10-High Economic
Growth Loads g.LowE~•e1
15-Clean Portfolio b
2045
7-WRAP PRM No QCC
Changes
Growth Loads
8-VE Rs Assigned to
Washington
6-WRAP PRM
1-Preferred Resource
Strategy
16-Social Cost Included
for Idaho
$0
$1 ,200 $1 ,250 $1 ,300 $1 ,350 $1 ,400 $1,450
Levelized Revenue Requirement Millions
2023 Electric IRP
$1,500
10-16
Chapter 10: Portfolio Scenario Analysis
Another metric used to evaluate portfolio risk combines the PVRR and Tail-Var95 values.
This is done by taking the present value of all future Tail-Var95 values and totaling this
value with PVRR. These results are shown in Figure 10.5 and are sorted from the highest
total cost to the lowest cost. Due to most of the resource acquisitions occurring toward
the end of the plan and the differing amounts of load included in each of the portfolios,
this metric is not as informative for scenarios with differing loads. Figure 10.6 was created
for 2045 to address these concerns. In this case, the total cost of the year is divided by
the load, then the TaiIVar95 risk value is added. The values shown in this figure are in
cents per kWh. This methodology demonstrates each of the scenarios on a more equal
footing. In this view, the risk additions compared to the total costs are low due to the
overall size of the rate base of the total utility cost. In addition, most of the resources
serving load have volumetric risk rather than natural gas price risk, except for the Idaho
portion of load.
Figure 10.5: Portfolio PVRR with Risk Analysis
14-Combined Electrification $1,406 $470 $1,876
4-No Resource Additions $1,248 $61 3 $1 ,861
12-WA Space/ Water Electrification $1 ,371 $476 $1 ,847
13-WA Space/ Water Electrification w/NG Backup $1,325 $474 $1,800
17-WA Maximum Customer Benefits $1 306 $479 $1,786
11-High Electric Vehicle Growth $1,306 $471 $1 ,776
10-High Economic Growth Loads $1 ,288 $1 ,773
5-No CET N No new NG $1 ,274 $1,754
3-Baseline Portfolio $1263 $1 ,750
1-Preferred Resource Strategy $1275 $1 ,736
15-Clean Portfolio by 2045 $1 287 $448 $1,734
8-VERs Assigned to Washington $1278 $456 $1,733
6-WRAP PRM $1,275 $454 $1,729
16-Social Cost Included for Idaho $1,277 $452 $1 ,729
2-Alternative Lowest Reasonable Cost Portfolio $1,267 $462 $1 ,729
7-WRAP PRM No QCC Changes $1 ,266 $446 $1,712
9-Low Economic Growth Loads $1,260 $421 $1,681
500 1,000 1,500 2,000 2,500
■ System Levelized PVRR ($ Mill) PV 2045 Tail Risk($ Mill) Total
The 2045 analysis also shows the PRS compared to other portfolios is the least risk
adjusted for costs where the portfolio meets reliability and regulatory objectives (Portfolios
#2, #3, #4, #5, and #7). The only portfolios with lower risk adjusted costs are dependent
on outcomes beyond A vista's control such as high load growth (#10, #11 ). The analysis
Avista Corp 2023 Electric IRP 10-17
Chapter 10: Portfolio Scenario Analysis
also shows, as in other portfolio summary information, the added costs for the high
electrification and higher clean energy requirements compared to the PRS . Since this
analysis summarizes customer cost, the societal benefits should overcome these added
customer costs to be a preferred resource strategy.
Figure 10.6: 2045 System Energy Cost w/ Risk
17-WA Maximum Customer Benefits
14-Combined Electrification
15-Clean Portfolio by 2045
12-WA Space/ Water Electrification
13-WA Space/ Water Electrification w/NG Backup
9-Low Economic Growth Loads
6-WRAP PRM
16-Social Cost Included for Idaho
8-VERs Assigned to Washington
1-Preferred Resource Strategy
7-WRAP PRM No QCC Changes
11-High Electric Vehicle Growth
10-High Economic Growth Loads
5-No CETA/ No new NG
2-Alternative Lowest Reasonable Cost Portfolio
3-Baseline Portfolio
4-No Resource Additions
Revenue Requirement
■Tai1Var95
25.09 .:.::~-== I 25.90
24_32 ::=== I 24.88
23.78 ===== I 24_31
23_21 I 24_24
22 08 ==== I 22.82
21 .n ==== I 22.16
21.44 I 22.26
21 .11 -~-• 21.91
20.85 ====· 21.53
20.91 I 21 .68
20.69 I 21 .39
___ 20.12 __ I 21.39
20.51 I 21.43
20.33 I 21.58
___ 20.05 I 20.93
19.04 __ I 19.82
11.89 I 18.64
5 10 15 20 25 30
Cents per kWh
Greenhouse Gas Emission Comparison
35
All resource strategies going forward will have greenhouse gas emission reductions
compared to current emissions. The reductions are largely due to Colstrip Units 3 & 4
leaving the system after 2025. Further reductions will be from reduced dispatch of existing
natural gas facilities due to Washington's Climate Commitment Act (CCA) and
Lancaster's PPA extension ending at the end 2041. While each portfolio has reductions ,
the reduced amounts are not all equal. Each portfolio's 22-year reduction levels are
shown in Figure 10.7. The data used for this chart is the gross emissions from Avista's
existing and selected controlled generating resources in blue and the green bars
represent the net emissions when there are sales or purchases in the wholesale energy
Avista Corp 2023 Electric IRP 10-18
Chapter 10: Portfolio Scenario Analysis
market. Market transactions include an emissions rate factor of 0.437 metric tonnes per
MWh as defined by CCA, while market sales use the estimated emission intensity of the
Avista facilities.
The #15 Clean Portfolio by 2045 has the greatest reduction levels using both metrics and
the #3 Baseline Portfolio has the least reduction on a gross level. The only portfolio
showing an increase is the theoretical portfolio #5 where the amount of market purchases
creates a high-emissions total due to the 0.437 metric tonne per MWh assumption. It is
worth noting the 0.437 intensity rate is an incremental rate and likely does not represent
the average emission intensity rate of market purchases especially as the system
decarbonizes.
Figure 10.7: Emission Reduction (Millions of Metric Tons (2045 compared to 2024)
15-Clean Portfolio by 2045
5-No CET N No new NG
16-Social Cost Included for Idaho
4-No Resource Additions
9-Low Economic Growth Loads
12-WA Space/ Water Electrification
13-WA Space/ Water Electrification w/NG Backup
17-WA Maximum Customer Benefits
14-Combined Electrification
7-WRAP PRM No QCC Changes
11-High Electric Vehicle Growth
1-Preferred Resource Strategy
6-WRAP PRM
8-VERs Assigned to Washington
10-High Economic Growth Loads
2-Alternative Lowest Reasonable Cost Portfolio
3-Baseline Portfolio
2.81
1.70
-1 .0 -0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5
■ Net Emission Change (MMT)
■ Generation Emissions Change (MMT)
Avista Corp 2023 Electric IRP 10-19
Chapter 10: Portfolio Scenario Analysis
The second metric for evaluating greenhouse gas emissions is the cost and emission
reductions compared to the PRS. Figure 10.8 shows the added PVRR cost compared the
PRS and to the total emissions changes over the 22-year study horizon -the emission
quantification used is the gross emissions generated from Avista controlled facilities. For
example, the #14 Combined Electrification Portfolio increases cost by $1.5 billion PVRR
over the PRS and the Greenhouse Gas (GHG) emissions are 0.23 million metric tonnes.
Portfolios in the bottom left quadrant have lower cost and lower emissions compared to
the PRS . These portfolios -do not meet current reliability or regulatory requirements.
Figure 10.8: Change in Emissions Compared to Portfolio PVRR
2,000
IJj 1,500 • 14-Combined
Electrification C: .2
~
c::: 1,000 13-WA Space/ Water
Electrification w/NG
c::: > a.
E 500
Q) ..... IJj >. Cl)
C: 0
Q)
C>
C: (ti
J:: -500 u
15-Clean Portfolio by Bae~ 11-High Electric
2045 I. Vehicle Gmwth 17-WA Ma,im,m Ii 5-No CETN No oew ~ Customer Benefits
NG mic
16-Social Cost / Growth Loads 8-VERs Assigned to Included for Idaho
I ,_---------Washington \ /
M~ 2-Alternative Lowest ~ / 6-WRAPPI ~ Low Economi
Reasonable Cost
Portfolio 3-Baseline Portfolio Growth Loads 4-No Resource
Additions 7-WRAP PRM No
QCC Changes
-1,000
-3 -2 -1 0 1 2 3 4
Change in 22yr Total Greenhouse Gas Emissions (MMT)
Market Price Sensitivities
This IRP considers three alternative market price sensitivities to understand the impact
to the portfolio choices. These market sensitives are discussed in Chapter 8 including the
specific assumption changes and the resulting market price effects. This section shows
how portfolios with different resource selections perform these future market scenarios.
Only portfolios with different resource choices for the same load objective are studied.
These include the PRS, the #3 Baseline Portfolio and the #15 Clean Portfolio by 2045.
For the National GHG Pricing sensitivity, a new portfolio demonstrates how Avista could
best minimize cost if this future materializes.
Avista Corp 2023 Electric IRP 10-20
Chapter 10: Portfolio Scenario Analysis
The first set of analyses shows the change in system PVRR and emissions changes for
the three portfolios in Table 10.4 compared to the Expected Case's market pricing. For
emissions, the amounts measured in this analysis are the average emissions of the
generation facilities over the period of the IRP.
The results for the High Natural Gas Price sensitivity show all portfolios have higher costs
compared to using the Expected Case's market pricing, but the clean portfolio shows the
greatest protection from higher costs. In the Low Natural Gas Price sensitivity, the
opposite occurs where the #3 Baseline Portfolio has the most benefit, but all portfolios
benefit by lower pricing. As the #3 Baseline Portfolio does not meet regulatory
requirements for Washington , the PRS shows the best outcome. However, this analysis
illustrates the resource choices in the PRS for Idaho provide the best outcome in low
natural gas pricing environments. In all portfolios, higher natural gas prices lead to less
emissions, while low prices lead to higher emissions. Although, if market related emission
were considered the emission levels may not be different.
For the National GHG pricing scenario the PVRR is largely unchanged due to Avista's
clean portfolio without coal generation and minimal natural gas, but the emissions are
less in this scenario.
Given the differences in policy objectives between Washington and Idaho, a separate
analysis was created for Table 10.5 to show how costs differ for the three portfolios. This
analysis shows Washington has greater cost projection in high natural gas pricing
environments compared to Idaho, but Idaho has greater cost protection in low natural gas
pricing futures. As in a future with a National GHG price, Washington's portfolio will see
a benefit to system cost, where Idaho may have a marginal increase. The increase is
mitigated due to the Expected Case Pricing including a portion of these costs due to an
increased probability of a future carbon pricing policy at the national level.
Table 10.5: PVRR and Emission Changes
Avista Corp 2023 Electric IRP 10-21
Chapter 1 O: Portfolio Scenario Analysis
Table 10.6: Jurisdiction PVRR Sensitivity Analysis
Change in PVRR vs Expected Case Market Pricing
Washington Idaho
High NG Low NG National High NG Low NG National
Prices Prices GHG Price Prices Prices GHG Price
Portfolio
1-Preferred Resource Strategy ··-··--3-Baseline Portfolio -0.1% 2.8% -3.8% 0.0%
15-Clean Portfolio by 2045 1.3% -2.7% -0.2% 2.3% -3.4% 0.0%
National GHG Pricing Portfolio
If a national GHG gas pricing plan were passed by the US Congress, Avista would deviate
from the PRS described in this IRP. Avista created a new optimized portfolio for this
future. This portfolio includes several changes from the PRS. The resulting changes
reduce the system PVRR by only $13 million (0.1 %) but include several portfolio changes
shown in Table 10.6 below. The most significant changes are increases in wind, storage,
and baseload renewable resources for Washington. This is likely due to higher market
prices justifying a change in resources to meet capacity and clean energy requirements.
Idaho's changes are far less dramatic, where natural gas is still preferred , but at a lower
amount in exchange for increases in energy storage, plant upgrades, and energy
efficiency.
Table 10.6: Jurisdiction PVRR Sensitivity Analysis
Washington Idaho
Resource Selection 1-18-Change 1-18-Change
Preferred National Preferred National
Resource GHG Resource GHG
Strategy Pricing Strategy Pricing
NGCT 0 0 0 304 277 -27
Solar 10 10 0 0 0 0
Stora e Added to Solar 0 0 0 0 0 0
Wind 945 1,145 200 0 0 0
130 469 339 67 119 52
H dro en/Ammonia 696 318 -378 0 0 0
Other "Clean" Baseload 0 78 78 0 0 0
Existin des 0 3 3 0 2 2
DR Ca 7 7 0 0 0 0
57 57 0 24 25 1
59 59 0 24 25 1
Avista Corp 2023 Electric IRP 10-22
Chapter 11 : Washington Customer Impacts
11. Washington Customer Impacts
Section Highlights
• Avista's 2021 Clean Energy Implementation Plan (CEIP) was approved with 38
conditions by the Washington Utility and Transportation Commission.
• Seven Customer Benefit Indicators (CBI) are applicable to resource planning.
• The non-energy impacts are used to enhance resource selection by accounting
for benefits to customers.
• Avista's planning methodology for CBls was reviewed by the newly formed
Equity Advisory Group (EAG).
• Avista created a Named Community Investment Fund (NCIF) to increase
energy related investments in disadvantaged communities.
Consistent with the Clean Energy Transformation Act (CETA) Standards in WAC 480-
100-610 (4) (c), and in accordance with the required content of an Integrated Resource
Plan (IRP) described in WAC 480-100-620 (9), this IRP includes an assessment of energy
and non-energy benefits and the reductions of burdens to Vulnerable Populations and
Highly Impacted Communities (i.e., Named Communities); long-and short-term public
health and environmental benefits, costs, and risks; and energy security risks. These
impact areas are considered in various portfolio analyses and incorporated into the
Preferred Resource Strategy (PRS) through the inclusion of non-energy impacts (NEis)
and Customer Benefit Indicators (CBls) metrics where applicable. Using these metrics,
Avista estimates the degree to which these benefits will be equitably distributed and/or
burdened over the planning horizon.
Including these requirements in resource planning, as well as resource and program
selection (occurs outside the IRP process), ensures a focus on communities who may
have historically been excluded from receiving the benefits of resources or programs.
Further, it provides a method to measure the success of the clean energy transition and
maintains accountability for Avista's resource and program choices. While Avista is
committed to ensuring the equitable implementation of the specific actions identified in
the Clean Energy Implementation Plan (CEIP), there are several circumstances where
NEis or CBls are not applicable to the long-term planning process. In these
circumstances, NEis and CBls are utilized for the evaluation and selection of programs
offered by Avista or in resource selection through a proposal process. The 2021 CEIP
was approved in Docket No. UE-210628 with 38 numbered conditions. In accordance
with CEIP Condition No. 2, Avista consulted with its Technical Advisory Committee (TAC)
and Energy Efficiency Advisory Group (EEAG) in the review of each resource, program
selection and/or implementation. In addition, the methodology was reviewed with the
Equity Advisory Group (EAG) to ensure the evaluation is equitable.
Avista Corp 2023 Electric IRP 11-1
Chapter 11 : Washington Customer Impacts
This chapter provides a review of each CBI and its relationship to resource planning,
selection, and implementation in accordance with Condition No. 35, stating:
A vista recognizes that not all CB/s will be relevant to resource selection (for
example, some CB/s pertain to program implementation). For its 2023 /RP
Progress Report, and future IRPs and progress reports, Avista should
discuss each CBI and where the CBI is not relevant to resource selection,
explain why.
Equity Impacts
CETA requires a focus on equity and Energy Justice. The core tenants of Energy Justice
include the following:1
• Distribution justice refers to the distribution of benefits and burdens across
populations. This objective aims to ensure marginalized and vulnerable
populations do not receive an inordinate share of burdens or are denied access to
benefits.
• Procedural justice focuses on inclusive decision-making processes and seeks to
ensure that proceedings are fair, equitable, and inclusive for participants,
recognizing that marginalized and vulnerable populations have been excluded
from decision-making processes historically.
• Recognition justice requires an understanding of historic and ongoing inequalities
and prescribes efforts that seek to reconcile these inequities
• Restorative justice uses regulatory government organizations or other
interventions to disrupt and address distributional, recognitional, or procedural
injustices, and to correct them through laws, rules, policies, orders, and practices.
These requirements create a new perspective for resource strategy evaluation within the
traditional IRP planning process through increased stakeholder input regarding equity
issues and continuous progress evaluation. Throughout the CEIP process, the EAG was
instrumental in identifying communities or individuals who have historically, or who are
currently, experiencing inequities. Avista has taken a first step to incorporate "recognition
justice" into its planning efforts. These groups are described in the "Named Communities"
section below. The equity areas identified under CETA are categorized and briefly
discussed in Table 11.1.
CBls were developed in the 2021 CEIP process to measure the equitable distribution or
"distribution justice" of the benefits or reduction of burdens in resource or program
selection. In compliance with Condition No. 35 of the CEIP , additional information is
1 WUTC Docket UG-210755 Final Order 09, paragraph 56.
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provided below about the development and applicability of CBls to resource planning as
well as resource selection and program implementation.
Finally, a Public Participation Plan was filed with the Commission in April 2021 2 and
implemented to ensure Procedural Equity within the CEIP development. Avista continues
to improve its Public Participation Plan in collaboration with the EAG and its third-party
consultant, Public Participation Partners (P3). In addition, a Work Plan was filed for the
2023 IRP Progress Report and this IRP to provide TAC meeting topics and a discussion
forum for IRP inputs ahead of the meetings. The development of this IRP and
Washington's 2023 Electric IRP Progress Report includes feedback from the TAC, thus
ensuring representation from stakeholders and individuals where additional policies and
procedures may be identified and considered going forward.
Table 11.1: Named Communities
Topic Observations
Affordability • Factors impacting ability to pay for energy
• Balance of electric bill with other expenses
Energy Resilience • Factors such as location, condition, etc. limiting the ability to
and Security have power quickly restored
• Factors limiting the consistency and security of power
services
Access to Clean • Factors limiting the ability to access clean energy programs
Energy and services
• Language, cultural, and economic barriers
• Limited transportation electrification infrastructure
Environmental • Factors may result in a disproportionate impact to
environmental harm
• Housing conditions
• Location to pollution
Community • Factors going beyond individual socio-economic or
Development sensitivities
• Factors pertaining to larger groups of individuals
Public Health • Factors disproportionally impacting health associated with
social or environmental indicators
Named Community Identification
Avista must identify communities who are disproportionally impacted by adverse
socioeconomic conditions, pollution, and climate change to ensure planning and
implementation processes are fair and have an equitable distribution of clean energy
transition benefits. To do this Avista identifies two types of community groups,
2 See Docket UE-210295.
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Chapter 11: Washington Customer Impacts
Highly Impacted Communities and Vulnerable Populations (WAC 480-100-605), jointly
referred to as Named Communities and are defined as follows:
• Highly Impacted Community means a community designated by the Washington
Department of Health (DOH) based on cumulative impact analyses in section 24
of this act or a community located in census tracts that are fully or partially on
"Indian country" as defined in 18 U.S.C. Sec. 1151.12.
• Vulnerable Populations mean communities that experience a disproportionate
cumulative risk from environmental burdens due to:
o Adverse socioeconomic factors, including unemployment, high housing, and
transportation costs relative to income, access to food and health care, and
linguistic isolation; and
o Sensitivity factors, such as low birth weight and higher rates of hospitalization.
Avista relies on information provided by the Washington State Health Disparities Map
from the DOH to help identify the Highly Impacted Communities. For each census tract in
the state, the DOH developed a score to measure disparities between 1 and 10 for each
of the four categories shown in Figure 11.1 . Communities where the combined average
score of the four categories was nine or higher are considered Highly Impacted
Communities. The DOH also included any areas fully or partially within "Indian Country". 3
Environmental
Exposures
o NOx-diesel
emissions
o Ozone
concentration
o PM 2.5
concentration
o Populations near
heavy traffic
o Toxic releases
from facilities
Figure 11.1 : Named Communities
Environmental
Effects
o Lead risk from
housing
o Proximity to
hazardous waste
treatment facilities
o Proximity to risk
management plan
facilities
o Wastewater
discharges
Socioeconomic
Factors
o Limited English
o No high school
diploma
o People of color
o Population living
in poverty(<=
185% of federal
poverty level)
o Transportation
expense
o Unaffordable
housing (>30% of
income)
o Unemployed %
Sensitive
Populations
o Death from
cardiovascular
disease
o Low birth weights
In the 2021 CEIP, Avista's methodology to determine Vulnerable Population
characteristics was conditionally approved.4 With the help of its EAG and other advisory
3 The DOH's list of Highly Impacted Communities originally included areas misidentified as "Indian" country
due to GIS borderline errors. Avista excluded these census tracts from its list for this report.
4 Docket No. UE-210628
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Chapter 11 : Washington Customer Impacts
groups, Avista determined the geographic boundaries of Vulnerable Populations for the
2021 CEIP by using the Health Disparities Map's5 community rating system for
Socioeconomic Factors and Sensitive Population. The map identifies areas on a scale of
1 to 10, where 10 is an area with the most significant health disparity. Avista focused on
identifying census tracts not otherwise identified as a Highly Impacted Community whose
socioeconomic factor or sensitive population score was 9 or 10. This methodology was
conditionally approved and contingent upon the incorporation of additional metrics as
identified by Avista and its EAG. The maps of both types of Named Communities are
shown in Figure 11.2 through Figure 11.4. Avista will continue to work with the EAG to
identify additional criteria to distinguish Vulnerable Populations.
A VISTA"
Figure 11.2: Spokane Named Communities
Named Communities
Legend
H9hly Impacted Convnunlty
Vulnerable ~lation
c:J Avista CEP Census Tracts
D Avista CEIP Electrtc Servi<:, Area
SpoU~County.
5 https://doh . wa. gov /data-a nd-statistica I-reports/washinqton-tracki nq-network-wtn/wash inqton­
envi ron mental-hea lth-d ispa rities-map
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Figure 11.3: Washington Service Area Named Communities
Legend
CJ A,~a ctlP C'""' ?tK1J
c:::J lf,.t.t COP 8o..D-< So-.aAro,
C, C I
...
0 25
Avista Corp 2023 Electric IRP 11-6
Legend
D Avisai WP c-lnKJS
CJ AY$aCflP6cari(Ser,,uAr1111
Chapter 11: Washington Customer Impacts
Figure 11.4: Clarkston Area Named Communities
Clarkston Named Communities
4 Miles
Non-Energy Impacts (NEI)
In certain circumstances, the impacts associated with energy efficiency (i.e., demand­
side) or supply-side resources may include additional effects beyond energy or bill
savings. These NEis may be significant compared to energy savings and are typically
separated into specific areas as follows:
• Utility Impacts -changes in resource cost, transmission and distribution losses,
and demand, leading to reductions in the number of resources needed to serve
customers.
• Societal Impacts -benefits or burdens associated with broader economic
development or environmental benefits such as regional reductions in emissions.
• Participant Impacts -benefits or burdens which extend beyond energy bill savings
including improvements in comfort, lighting quality, equipment operations and/or
maintenance, health, and safety, etc. These impacts may also be related to public
health, safety, reliability and resiliency, energy security, environment (land use,
water, wildfire, wildlife), and economic impacts.
NEis have been incorporated in the selection of energy efficiency6 programs/measures
previously but using NEis is new in respect to supply-side resource planning. Avista
6 NEI for energy efficiency resources were incorporated into the 2021 IRP on an overall basis rather than
individual measure basis.
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engaged with a consultant, DNV7, to identify and quantify both energy efficiency and
supply-side NEis. After input from recent Washington Utilities and Transportation
Commission (WUTC) workshops and Avista's advisory groups, additional quantified
NEls8 will be included in resource planning efforts for energy efficiency and supply-side
resources as identified in the most recent NEI study. Quantification of additional NEis
may be included in the future as more studies are completed, specifically for solar,
storage, demand response and other distributed energy resources (DERs). As part of
CEIP Condition No. 2, Avista greed to incorporate NEis in the 2023 IRP Progress Report
as well as this and future IRPs. Outside the resource planning process, NEis are also
helpful in resource selection and utilized in Avista's 2022 All-Source Request for Proposal
(RFP).
For energy efficiency, Avista only uses the positive NEI values applied as a levelized cost
per kWh for applicable measures. While the NEI values vary between measures and
sectors, the largest area of benefit is with low-income residential customers.
Weatherization measures such as windows , insulation, and insulated doors have
received the highest overall NEI values with Health and Safety being the largest overall
contributor; these values are up to $0.75 per kWh. These studies and a summary of how
these NEis were calculated is included in Appendix D.
DNV also studied NEis for potential and existing supply-side resources. Costs or benefits
were estimated at a $/MWh of production-based impacts, such as air emissions or $/kW
of project size (levelized over the life of the asset) as economic impacts. The DNV report
for this study is in Appendix D and was also presented to the IRP TAC. The NEI value for
resources is in the PRiSM model and was used to select new resources.
NEI values can be useful in resource planning, obtaining additional NEis quantification is
too expensive to estimate for a utility of Avista's size. As such, it would be more efficient
to determine consistent estimates on a regional basis. Many of the non-quantified values
from the studies require more research, analysis, and peer review to develop proxy
values.9 The additional NEI items could best be handled through a joint utility funded NEI
study, potentially directed by the WUTC.
Named Community Investment Fund
To increase focus on the equitable distribution of projects and programs, the Named
Community Investment Fund (NCIF) was proposed and approved, 10 as part of A vista's
2021 CEIP. This fund facilitates investments in programs, projects, initiatives, and other
support that traditionally would not be undertaken.
7 https://www.dnv.com/
8 Avista also include proxy NEI values for resources without an NEI identified in the DNV study.
9 Such as the 10 percent adder for energy efficiency in the Northwest Power Act.
10 See Order 01 in Docket UE-220350
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Avista proposed to spend up to approximately $5 million, or 1 percent of its electric retail
revenue at the time, each year of the 2021 CEIP implementation period through the NCIF
on projects to improve the equitable distribution of energy and non-energy impacts within
Named Communities. The NCIF allocation is as follows:
• 40 percent or up to $2 million to supplement and support Avista's targeted energy
efficiency efforts for Named Communities. If approved, this funding would be
recovered through the energy efficiency tariff rider (Schedule 91 -Energy
Efficiency).
• 20 percent or up to $1 million for distribution resiliency efforts for Named
Communities.
• 20 percent or up to $1 million for incentives or grants to local customers or third
parties to develop projects benefitting Named Communities.
• 10 percent or up to $500,000 for targeted outreach and engagement efforts in
Named Communities to reduce barriers to participation for their access to energy.
• 10 percent or up to $500,000 for all other projects, programs, or initiatives
benefitting Named Communities.
Avista focused its recent efforts on developing a NCIF governance structure to include
project identification, application, application requirements, evaluation, and selection
criteria. The Energy Efficiency Department will oversee the planning, resource allocation,
and implementation of approximately $2 million allocated to energy efficiency projects.
One quarter of the $2 million, is dedicated to partnering with A vista's EAG on community­
identified projects. Avista will work closely with the EAG and EEAG for input and feedback
on program design and outreach methods. Meeting notes and recordings about NCIF
discussions with the EAG are on Avista's website.11 A placeholder for potential projects
considered within the IRP are discussed in Chapter 9.
Customer Benefit Indicators
This IRP includes forecasts of the relevant CBI impacts for supply or demand side
resource selection . As illustrated in Table 11.2, the CEIP includes 14 CBls, including
several metrics for measuring the impact of those CBls. The metrics boldly highlighted
are forecasted in this IRP since they're relevant to resource planning. These metrics will
measure the effects of the clean energy transition and broaden the focus on equity among
customers.
In some cases, there is a direct correlation between a CBI and an NEI. For instance, the
CBI to reduce air emissions includes the estimated financial value of the societal harm of
those emissions as an NEI. As such, energy efficiency addresses CBls in its NEI
calculations for resource planning purposes. For metrics related to resource planning, this
IRP shows both available historical baselines and a forecast for these CBls.
11 https://www.myavista.com/about-us/washingtons-clean-energy-future
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While Avista is committed to ensuring the equitable implementation of the specific actions
identified in the CEIP, there are circumstances where NEis or CBls are not applicable to
the resource planning process. In these circumstances, NEis and CBls are utilized for
evaluation and selection during the resource selection and program implementation
processes. Figure 11.5 illustrates the planning process for resource needs and how those
resources are secured and implemented, and how they impact the next IRP's load and
resource needs. Some CB ls have data available to forecast on a long-term basis and can
be included in the IRP, while others will take CBls into consideration when evaluating
options during implementation. The applicability and timing of CBI inclusion is described
below. In either circumstance, Avista is measuring and tracking the impact of business
decisions to focus on equitable outcomes.
Figure 11.5: Planning Process
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Table 11.2: Customer Benefit Indicators
CBI CBI Measurement Metrics
(1) Participation in Participation in weatherization programs and energy assistance
Company Programs programs (all customers and Named Communities)
Saturation of energy assistance programs (all customers and Named
Communities)
Residential appliance and equipment rebates provided to customers
residing in Named Communities and rental units (Condition No. 17)
(2) Number of Number and percent of households (known low income, all
households with a High customers, Named Communities) (Condition No. 18)
Energy Burden (>6%) Average excess burden per household
(3) Availability of Number of outreach contacts
Methods/Modes of Number of marketing impressions Outreach and Translation services (Condition No. 19) Communication
(4) Transportation Number of trips provided by Community Based Organizations (CBOs)
Electrification for individuals utilizing electric transportation
Number of annual passenger miles provided by CBOs for individuals
utilizinq electric transportation
Number of public charging stations located in Named Communities
(5) Named Community Total MWh of distributed energy resources 5 MW or less
Clean Energy Total of MWh of energy storage resources under 5 MW
Number of sites/projects of renewable distributed energy resources
and energy storage resources
(6) Investments in Incremental spending each year In Named Communities
Named Communities Number of customers and/or CBOs served
Quantification of energy/non-energy benefits from investments (if
aoolicable)
(7) Energy Availability Average outage duration
Planning Reserve Margin (Resource Adequacy)
Frequency of customer outages
(8) Energy Generation Percent of generation located in Washington or connected to
Location Avista transmission
(9) Outdoor Air Quality Weighted average days exceeding healthy levels
Avista plant air emissions
Decreased wood use for home heating
(10) Greenhouse Gas Regional GHG emissions
(GHG) Emissions Avista GHG Emissions
(11) Employee Diversity Employee diversity representative of communities served by 2035
(12) Supplier Diversity Supplier Diversity of 11 percent by 2035
(13) Indoor Air Quality In development
(14) Residential Number and percent of residential electric disconnections for non-
Arrearages and payment
Disconnections for Residential arrearages as reported to Commission in Docket U-200281
Nonpayment
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CBls Not Applicable to Resource Planning
The following CBls are not related to the resource planning phase. These items will be
utilized in resource selection, program implementation, or evaluation to focus on equity
areas. In accordance with Condition No. 35, the following information is applicable to
these CBls.
CBI No. 1 -Participation in Company Programs
This CBI aims to increase overall participation levels for all customers in Avista's energy
efficiency and energy assistance programs, with special emphasis on Named
Communities. While the priority is to increase participation within Named Communities
specifically, Avista will consider the current participation levels in energy efficiency
programs as part of its baseline when measuring increases to participation. The intent of
these efforts is to prioritize distributional equity by addressing direct or indirect barriers
impacting a customer's ability to participate in energy efficiency programs.
This metric emphasizes overall participation; however, the impact of these efforts is
directly related to reducing customers' overall energy burden and making energy more
affordable. Energy Efficiency efforts have known energy and NEI values with direct
benefits to customers from both affordability and overall wellbeing standpoints. When
combined with CBI No. 3, Avista can monitor the successful steps contributing to this
increase in participation. The Company will monitor the following metrics included in this
CBI:
• Participation in weatherization, efficiency, and energy assistance programs (all
customers and Named Communities);
• Saturation of energy assistance programs (all customers and Named
Communities); and
• Residential appliance and equipment rebates provided to customers residing in
Named Communities and rental units (Condition No. 17).
Tracking the metrics for this CBI is granular in nature and requires data for each individual
customer, as well as each customer in a Named Community. This requires extensive data
analysis utilizing Avista's Customer Care and Billing system. In IRP planning, energy
efficiency is forecast based on a total energy savings by program type and customer
segment (i.e., residential and commercial customers). Typically, those energy efficiency
measures identified to be cost effective through the conservation potential assessment
(CPA) are implemented, but the IRP doesn't go to the individual customer level as
required in this CBI. The EEAG will be instrumental in developing a method for prioritizing
programs to ensure they are equitably distributed.
CBI No. 3 -Availability of Method/Modes of Communication
This CBI focuses on increasing access to clean energy and reaching customers who have
not participated in Avista energy efficiency and energy assistance programs due to
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Chapter 11: Washington Customer Impacts
language barriers or other limitations such as not knowing about the programs or
understanding the application process. Increased participation will lead to lower energy
usage and costs, while positively impacting accessibility and affordability. This CBI seeks
to increase participation in energy efficiency programs. The metrics for this CBI are:
• Number of outreach contacts;
• Number of marketing impressions; and
• Translation services.
These barriers to access make it more difficult and expensive for Named Communities.
Increased and expanded customer outreach will grow energy efficiency and energy
assistance participation making energy service more affordable for disadvantaged
customers. Further, increased energy efficiency participation benefits all customers by
reducing the need for more generation. This CBI is not relevant to resource planning but
rather to program implementation. Avista continually works with its advisory groups to
increase participation.
CBI No. 4 -Transportation Electrification
This CBI considers Transportation Electrification (TE) efforts and impacts on customers
in Named Communities. Avista's Transportation Electrification Plan (TEP)12 provides a
path to a cleaner energy future by 2045 by electrifying transportation. The TEP outlines
guiding principles, strategies, and an action plan with detailed program descriptions, cost
and benefit estimates, and regular reporting details. The TEP has an aspirational goal of
investing 30 percent of Avista's total transportation electrification spending on programs
benefiting disadvantaged communities, low-income customers, or Named Communities.
Tariff Schedule 77 and the TEP commits to regular reporting of TE efforts through several
metrics.
Avista will track TE in Named Communities with three metrics:
• Annual trips provided by Community Based Organizations (CBOs) by electric
transportation;
• Annual passenger miles provided by CBOs by electric transportation; and,
• Public charging ports available to the public in Named Communities.
The impacts of TE are embedded in Avista's load forecast and its resource planning
process. This accounts for TE at a high level during the planning process. During TE
program implementation, much detail is required to focus where the impacts of efforts will
be located. Avista will continue collaboration with CBOs to ensure a focus on Named
Communities throughout the implementation process.
12 WUTC Docket UE-200607, acknowledged by the Commission on October 15, 2020.
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CBI No. 6 -Investments in Named Communities
This CBI targets new investments in Named Communities that may lead to positive
impacts on Avista customers living in these communities. Benefits may include lower
energy burdens, economic development, affordability, resiliency, or other safety and
health matters. The potential investments will not include capital , O&M , energy efficiency,
or energy assistance already deployed in the normal course of business. This CBI
focuses on the equitable distribution of non-energy and energy impacts to all customers
and specifically those in Named Communities.
Avista will measure the following metrics for this CBI:
• Incremental annual spending of NCIF and other investments in a Named
Community;
• Number of customers and/or CBOs served each year; and ,
• Applicable quantification of annual energy and non-energy impacts from
investments.
Avista includes a related forecast of potential NCIF investments later in this chapter, the
results use total low-income energy efficiency investments, energy resources developed
from the NCIF and pro-rata share of selected demand response (DR). Due to the
investment required from this CBI, the forecast is an indicator of potential investments to
be tracked in this CBI.
CBI No. 7 -Energy Availability
This CBI aims to ensure customers in Named Communities are not disproportionally
impacted by delivery system or resource adequacy power outages due to their socio­
economic or sensitivity factors. This CBI tracks the location of outages and will inform
future implementation and system development to minimize the potential for outages.
Avista will measure the following metrics.
• Average Outage duration by Customer Average Interruption Duration Index
(CAIDI) -Not included in resource planning;
• Frequency of Customer Outages by Customer Experiencing Multiple Interruptions
(CEMI) -Not Included in resource planning; and
• Planning Reserve Margin (Resource Adequacy) -Included in resource planning .
Avista has a duty to provide safe and reliable energy to its entire customer base. Historical
customer outage information provides customers with a measure of resiliency and
reliability by calculating the time it takes to restore a customer's service from an outage
but does not show the cause of the outage. Most outages have been related to the
distribution system and can be interrupted by weather, equipment failure, maintenance,
or other factors. Monitoring these two metrics will provide data and inform Avista where
new distribution resources may be located to best address inequities. The newly formed
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Distribution Planning Advisory Group (DPAG) will provide insight into this distribution
process.
In other instances, customer outages may be due to a lack of resource adequacy. The
Planning Reserve Margin metric attempts to isolate Avista's ability to generate enough
energy to meet customer demand while ensuring reliability through resource generation
additions. This metric is included in resource planning as each demand-and supply-side
resource may result in different degrees of reliable energy and is dependent upon types
of resource. Please see the section on CBls applicable to resource selection for more
information.
CBI No. 9 -Outdoor Air Quality
Displacing fossil fuel generation will help outdoor air quality metrics with the reduction of
S02, NOx, Mercury, and Volatile Organic Compounds (VOC). Avista will track the
following metrics for this CBI :
• Weighted average days exceeding healthy levels;
• Decreased wood use for home heating; and
• Avista's Washington resource air emissions.
The impact to the total weighted days exceeding healthy levels will be from Avista's efforts
to reduce emissions and actions taken by others in the service territory. This metric is not
included in the resource planning process.
Decreased wood use for home heating is not quantifiable at this time on a 20 plus year
planning horizon and is not part of the resource planning process. However, Avista will
continue to partner with the Spokane Regional Clean Air Agency to track wood use as a
primary heating source. Avista will work with its EAG to develop an alternative method
per CEIP Condition No. 20 and track in resource planning if appropriate.
The final outdoor air quality metric is Avista's Washington resource air emissions, and it
is modeled in the IRP and will be included in resource and program selection and
implementation. Through the NEI study, Avista can quantify the impacts of certain
facilities' impacts to overall outdoor air quality. This is explained in the section below
discussing the metrics Avista utilized in the IRP.
CBI -No. 11 Employee Diversity and No. 12 Supplier Diversity
The purpose behind these CBls is to generate awareness and therefore promote
recognitional justice. Tracking employee diversity and supplier diversity is a first step in
recognizing the potential of systemic racism embedded within existing processes and
procedures. Tracking these metrics will result in an increased focus towards identifying
and changing policies to eliminate inequities. This CBI is not intended to be utilized as a
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resource planning metric; however, as an implementation tool Avista includes diversity
metrics in its selection criteria for resource selection.
The EAG raised the issue of ending systemic racism as a major concern and discussed
what Avista could do to help with this wide-ranging issue. CBls No. 11 and No. 12 are an
initial attempt to track and improve Avista 's employee diversity to match the diversity and
genders of the communities it serves. This aspirational goal will be tracked by craft, non­
craft, managers and directors, and executives for race and gender with a goal of matching
the communities being served by 2035.
CBI No. 13 -Indoor Air Quality
This metric will measure the impact of energy efficiency efforts on indoor air quality. It is
still in the development phase. Once this metric is developed and data is available, it will
be tracked and may be included in resource selection if applicable. Avista will provide an
update for this CBI in its Biennial CEIP Update Report to be filed by November 1, 2023.
CBI No. 14 -Residential Arrearages and Disconnections for Non-Payment
This CBI tracks residential arrearages and disconnections for non-payment. Connection
to energy service was identified by stakeholders as a key element of energy security. This
CBI is not applicable to resource planning. For planning purposes, a certain level of price
elasticity is included relating to the cost of resource selection and may ultimately impact
arrearages and disconnections for non-payment. Further resource decisions include the
cost of arrearages, while energy efficiency evaluations include this savings in the
calculation of avoided costs. Reporting this CBI keeps the issue at the forefront of
affordability and/or energy burden conversations during implementation of future
investments. Avista includes a utility NEI for a decrease in contact center calls for certain
low-income energy efficiency measures to account for reductions in future disconnects.
CBls Applicable to Resource Selection
While most of Avista's CBls are not related to resource planning, this section addresses
CBls with ties or linkages to resource planning. The intent of Avista's resource selection
methodology is to use resource costs and benefits, the NCIF, CETA requirements, and
NEI values to inform resource outcomes, while avoiding any preconceived CBI targets or
expectations. Constraints or requirements can be created in the PRiSM model to ensure
certain metrics are met such as the Planning Reserve Margin requirements or including
financial incentives such as NEis to incent certain decisions. These constraints may drive
different outcomes as compared with traditional planning. The following section outlines
CBI forecasts, while the specific data used to estimate the metrics and CBI values are
included with the PRiSM model in Appendix F. These results can also be measured
against a future scenario "Maximum Customer Benefits" scenario and are achieved
through increasing CBls values to theoretical levels. In the end , it will be discretionary if
the resource selection and the expected CBI outcomes are justified as equitable.
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CBI No. 2 -Number of Households with High Energy Burden
There are two forecastable metrics13 related to household energy burden included within
resource selection modeling:
• The number of households with energy burden exceeding 6% of income; and
• Average excess energy burden.
To assess current and future energy burden, data for customer income, energy usage,
and energy rates is required. Customer income data was derived from a spatial analysis
of census and third-party income data and was matched with usage and bill amount data.
Total energy burden includes all fuels, natural gas and electric, at a specific location.14
Forecasting this CBI requires assumptions regarding individual customer income and
usage along with the cost of non-electric household fuels. To forecast energy burden in
this analysis, customers are grouped by income, electric energy usage, and whether
customers have electric only vs combined electric and natural gas. Customer income is
escalated using the 2001-2021 historical income growth rate for each income group and
customer usage 15 is forecast using current energy use reduced by the amount of energy
efficiency selected for a specific income group.16 Lastly, the cost of the energy used by
the customer is estimated using a rate forecast based on the resources selected with the
IRP forecast. Beyond the assistance provided by the development of a low-income
community solar facility, the analysis does not consider additional energy assistance.
The first metric illustrates the forecast of the number of customers with excess energy
burden (see Figure 11.6) over the planning horizon. These customers have a combined
energy bill between electric and natural gas exceeding 6% of their income to be included
in this metric. Customers can fall into this metric due to high usage or low income. The
absolute number of customers with an energy burden increases by 6,569 by 2045, though
the percent of energy burdened customers is essentially flat at 20%. Avista expects to
increase the amount of energy assistance participation for those customers through
increased outreach and targeted programs.
13 At this time separate tracking on a forecasted basis for known low-income and Named Communities
cannot be completed until additional data is gathered. Avista intends to have this information available for
the CEIP Progress Report.
14 Currently the only non-electric household fuel expense included is natural gas. Estimated costs for other
fuels such as fuel oil, propane, and wood should be included, but are not available at this time.
15 This analysis does not include EV load in the energy usage calculation as it would unfairly place higher
electric costs on the customer without considering other transportation costs not included in the calculation.
16 Typical increases to energy usage (i.e., adding new technology and devices) for this purpose is being
ignored.
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Figure 11.6: WA Customers with Excess Energy Burden (Before Energy Assistance)
60,000
50,000
fl) 40,000 ,_
Cl)
E 0 30,000 ... ,,,
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10,000
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"d' l.t') 10 r--co Ol 0 ..... N M "d' l.t') 10 r--co Ol 0 ..... N M "d' N N N N N N M M M M M M M M M M "d' "d' "d' "d' "d' 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N
Avista will have approximately 280,000 Washington electric residential customers in 2023
and approximately 20 percent of these customers exceed the 6% threshold as shown in
Figure 11. 7 in 2024. Avista continues to refine this metric for historical baseline purposes.
The last customer energy burden metric is the amount of dollars per year of energy
assistance the customer would need to reduce their energy burden to the 6% level.
Excess energy burden growth is shown in Figure 11. 7 and Figure 11.8 shows the average
excess energy burden . This metric is expected to increase. Both the nominal and real
(2024 dollars) values are increasing, though the real increase is modest in comparison to
the nominal increase. The difference between the two demonstrates the impact of inflation
compared to the impact of rate increases.
25.0%
20.0%
15.0%
10.0%
5.0%
0.0%
Figure 11. 7: Percent of Washington Customers with Excess Energy Burden
~ ~ 10 ~ CO Ol O ..-N M ~ N N N N N N M M M M M 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N
Avista Corp 2023 Electric IRP 11-18
II')
"d' 0 N
Chapter 11: Washington Customer Impacts
Figure 11.8: Average Washington Customer Excess Energy Burden
""" It') <O r--00 a, 0 ... N M """ It') <O r--00 a, 0 ... N M """ It')
N N N N N N M M M M M M M M M M """ """ """ """ """ """ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N
Average excess burden per household
-Inflation adjusted excess burden per household (2024 $)
CBI No. 5 -Named Community Clean Energy
This CBI monitors and prioritizes investments in DERs under 5 MW; specifically,
generation and storage resource opportunities in Named Communities. This CBI has
three metrics:
• Energy produced from DERs;
• DER energy storage capability; and
• Number of projects in Named Communities.
The IRP forecast includes DER production and capacity, but the number of projects is
outside the planning scope and cannot be accurately forecasted . There are three
methods for bringing these resources to the system. The first is PURPA development.
Historically, this method has brought the most energy to Avista from developers building
resources and selling the output to Avista using the federal regulation requiring utilities to
purchase the output from qualifying facilities at the published avoided cost rates. The
second method is from customers participating in Avista's net metering program. These
resources are behind-the-meter customer resources where the energy produced is netted
against customers' consumption.17 The amount of these resources is outside utility control
and is based on whether the customer chooses to own their own generation. The last
category is small generation owned or contracted by Avista, typically this includes
community solar projects, but could include other investments from the NCIF or cost­
effective resource additions typically selected through an RFP process.
The historical and forecasted Named Community DER generation is shown in Figure
11.9. Most of the historical generation is from hydro-based generation and incremental
additions are projected to be from community solar projects funded by state incentives
17 Net metered generation in a Named Community was not available at the time of this report.
Avista Corp 2023 Electric IRP 11-19
Chapter 11: Washington Customer Impacts
and Avista 's NCIF. This plan includes expected storage related DERs to be added in
Named Communities to enhance distribution systems and provide system peak capacity.
The DER additions described above are shown in Figure 11.10.
Figure 11.9: Total MWh of DER in Named Communities
35,000 actual : forecast
30,000 . .
25,000 .
20,000 . .
..r:: .
:!: 15,000 ~ -:E --
10,000
5,000
0
"' ,-.. co "' 0 .... N v 1.() "' ,-.. co "' 0 .... N M v I/') "' ,-.. co "' 0 .... N M v I/')
0 .... 0 0 N N N N N N N N N M M M M M M M M M M v v v v v v 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
Avista partnered with the Department of Commerce in Washington on two Clean Energy
Fund Projects, to install DER energy storage in Named Communities. In 2020, 1.8 MWh
of storage was installed as part of a microgrid project in Spokane. An additional 1.3 MWh
will be installed as part of the Spokane eco-district project, and it is expected to be online
in April 2023. Each of the DER energy storage projects are co-located with solar assets
and are equipped with control systems to operate the assets in coordination with each
other and the grid. In addition to solar and energy storage, the eco-district site includes
thermal energy storage (both water and phase change) designed to provide electric load
shifting for the eco-district's central energy plant. The design estimated MWh equivalent
storage is approximately 0.6 MWh during summer months and 4.5 MWh during winter
months.
Figure 11.10: Total MWh Capability of Storage DER in Named Communities
8.0 actual : forecast
7.0 . . . .
6.0 . . . .
5.0 . . ..c: ::': 4.0 :::
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3.0
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Avista Corp 2023 Electric IRP
4.3
3.9
1.() IO
M M 0 0 N N
5.1
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11-20
Chapter 11 : Washington Customer Impacts
CBI No. 6 -Investments in Named Communities
This plan includes high level estimates for investments and benefits in Named
Communities. This CBI includes three metrics:
• Reduction of Energy Burden;
• Energy Resiliency; and
• Risk Reduction.
This illustration includes the annual utility invested cost of resources in this IRP and
compares these values to the annual utility and non-energy impacts discussed earlier in
this chapter. The resources are selected based on a cost-effective analysis including
utility (energy/capacity) and NEI benefits, except for the minimum spending constraint
from the NCIF. Figure 11.11 shows the projected investments and benefits. Resource
selection choices are driven by high non-energy impacts for energy efficiency in low­
income areas. Annual investment is driven by investments in energy efficiency.
Investments peak in 2029 and then decrease through 2039 as there are fewer energy
efficiency opportunities.
U)
C:
0
:§
Figure 11.11: Total MWh Capability of Storage DER in Named Communities
$50
$45
$40
$35
$30
$25
$20
$15
$10
$5
$0
c:::::::JAnnual Utility Benefits
c::::::iAnnual N El Benefrts
-Annual Investment
~FlFl
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0, 0 N M 0 0 N N
.... N M s:t 1/) "' ,.._ co 0, 0 .... N M
M M M M M M M M M s:t s:t s:t s:t 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N
s:t s:t 0 N
This CBI includes a third metric accounting for the number or sites and projections of
future DERs. This forecast does not include this metric as the number of project sites will
be determined during implementation.
Avista Corp 2023 Electric IRP 11-21
Chapter 11 : Washington Customer Impacts
CBI No. 7 -Energy Availability
This CBI is designed to ensure Avista has a reliable system for all customers including
Named Communities and has three metrics:
• Average Outage Duration;
• Planning Reserve Margin (Resource Adequacy); and
• Frequency of Customer Outages.
These metrics related to customer reliability, but only one is related to resource planning.
The other two are impacted by distribution system reliability from delivery system issues
as discussed above. The item applicable to IRP planning is the Planning Reserve Margin
(PRM) where the PRM is a minimum requirement for the amount of resource capability
during peak events. This metric is one of a few applying to the full Avista system rather
than just the State of Washington. Figure 11.12 shows the historic and forecasted
expected peak hour resource capability versus load. For the historical periods, the metric
shows the amount of actual generation or what could have been generated from Avista­
controlled resources compared to actual peak load within the same hour resulting in an
implied resource margin. After 2022 , the PRM is a forecast comparing future peak loads
and expected generation capability during peak hours using Qualifying Capacity Credit
(QCC) values.18 Future values exceed the current interim PRM of 22 percent in the winter
and 13 percent in the summer throughout the planning horizon as additional resources
are selected to address energy needs, and the expectations of the QCC values of
renewables and storage will fall.
Figure 11.12: Planning Reserve Margin
50%
45%
actual forecast ■Winter lilSummer
.:.::
(1' 40% Cl) a.. 35% Cl) > 30% 0 .c ~ 25%
-"C t: (1' 20% Cl) 0 ~ .... 15% Cl) a..
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0 Cl) 0% Cl)
0::
18 QCC values were derived by the Western Resource Adequacy Program with input from participating
utilities and compilation by the program administrator -SPP.
Avista Corp 2023 Electric IRP 11-22
Chapter 11: Washington Customer Impacts
CBI No. 8 -Energy Generation Location
CETA encourages the use of local resources to enhance energy security. As such, this
CBI will address the following metric:
• Percent of generation located in Washington or connect to Avista's
transmission system.
To address energy security, Avista quantifies the amount of generation located within
Washington State or directly connected to Avista's transmissions system used for
customer needs. These options should provide an increased reliability rate as potential
disruptions may be minimized by the proximality to load. This metric is energy agnostic
on the type of energy used. Figure 11.13 shows the historical generation mix and resource
selected mix of energy created in Washington or connected to Avista's transmission
system. The amounts are shown as a percentage of customer loads. Avista's Washington
and transmission connected resources will increase due to recent acquisitions from
Chelan PUD and Columbia Basin Hydro. In 2026, Avista will likely generate more local or
connected generation than its load and export the surplus to other utilities. Avista's
forecast shows a decrease in connected resources due to selection of external resources,
such as Montana wind. These resources are preferred due it its cost than local resources
due to necessary system transmission upgrade costs. Economic benefits of local
generation were included as a NEI, but these benefits are overshadowed by the high
costs of new transmission.
Figure 11.13: Generation in Washington and/or Connected to Avista Transmission
actual forecast
100% ;I.
~ 0 ' ... ' ' "C 80% "' :! Cll I ~ • 0 ;I. i ;I.
...J • I!? ... l -60% ' 0 ' ;I. -:1 ' r:: Cl/ (.) 40% ...
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<D r--co 0) 0 N N s:j' "' <D r--co 0) 0 ..... N M s:j' "' "' r--co 0) 0 ::; N M s:j' "' ..... .... .... .... N N N N N N N N M M M M M <"') "' M M M s:j' s:j' s:j' s:j' s:j'
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
Avista Corp 2023 Electric IRP 11-23
Chapter 11: Washington Customer Impacts
CBI No. 9 -Outdoor Air Quality
As discussed above, Avista's resource air emissions are forecastable within an IRP. The
Outdoor Air Quality CBI measures the following:
• Weighted average days exceeding healthy levels; and
• Avista's Washington plant air emissions.
The impacts to unhealthy days within local communities are typically related to events
outside of Avista's control and are after the fact calculations conducted by a third party.
The forecastable metrics include SO2, NOx, Mercury, and Volatile Organic Compound
(VOC) emissions from Avista's Washington plants. These forecasts are based on
emission rates per unit of fuel. These emissions are regulated by local air authorities and
meet all local laws and regulations for air emissions and are found to be at a level safe
for the local population. Associated NEis to ensure air quality improvements are
considered in resource selection.
The metric measures total annual emission levels for Washington State facilities including
Kettle Falls Generating Station (KFGS), Kettle Falls Combustion Turbine (CT), Boulder
Park, and Northeast CT. All metric results decline over the IRP planning horizon due to
lower thermal dispatch hours and increased efficiencies and controls at the KFGS with
the addition of Myna's biochar co-gen facility supplying steam rather than direct
combustion of woody biomass.19 Figures 11.14 through 11.17 demonstrate the projected
levels of emissions for each pollutant type. SO2 and VOC have the largest forecasted
changes which is due to the decrease in per unit emissions at Kettle Falls and its
decreased dispatch over the planning horizon. Avista does not directly monitor mercury
emissions for its natural gas facilities as the emissions are de minimis.
Figure 11 .14: Avista Located Washington State Facility's S02Emissions
s~------------------------------~
4
0
n n n n i'2, i'2, 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 . ,......., ,......., r-, r-, r-, r=:I r7 .-, ,......., r-, ,......., r-1 ,......., ,......., ,......., ,......., ,.......,
c.c r--co a, 0 ... N "<t I.O c.c r--co a, 0 ... N M "<t I.O c.c r--co a, 0 ... N M "<t I.O ... ... ... ... N N N N N N N N N M M M M M M M M M M "<t "<t "<t "<t "<t "<t 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
19 lfthe ammonia combustion turbines were sited in Washington state, NOx emission could increase subject
to SCR controls and amount of required dispatch.
Avista Corp 2023 Electric IRP 11-24
Chapter 11 : Washington Customer Impacts
Figure 11.15: A vista's Washington State Facility's NOx Emissions
500
400
(/)
C:
0 300 I-
(.) ·;:: ..... 200 (l) :E
100
0
Figure 11 .16: Avista's Washington State Facility's voe Emissions
60
50
,.._
(/) 40 ,-.:
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N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
CBI No. 10 -Greenhouse Gas Emissions
There are two metrics for GHG Emissions covered in this section:
• Avista's GHG emissions; and
• Regional GHG emissions.
The first metric estimates the amount of direct emissions from Washington's share of
power plants and how those change considering market transactions (labeled as "net
emissions"). Figure 11.18 shows direct GHG emissions rising until the end of 2025 when
Colstrip ownership is transferred and removed from Avista's portfolio. Emissions are
expected to be higher in the short run as the current energy market needs additional
dispatchable generation to meet loads with increasing levels of variable energy resources
but should decline as additional clean energy resources are brought on the western
interconnect system. Net emissions are lower than direct emissions in the near-term as
Avista Corp 2023 Electric IRP 11-25
Chapter 11 : Washington Customer Impacts
the calculation removes emissions related to power sold off the system. Later in the
planning horizon, system sales decrease and Avista may need to purchase power. This
forecast includes emissions associated with those purchases . Lastly, due to the Climate
Commitment Act (CCA) requirement of tracking emissions, this CBI may be modified to
reflect the required methodology of reporting emissions.
One of the main purposes of CET A is to reduce state level greenhouse gases. Electric
power specifically related to eastern Washington is small in relation to total emissions.
The second GHG metric (shown in Figure 11.19) shows the direct utility emissions plus
emissions from other sectors. Placing Avista emissions in the context of all emissions
allows for a wholistic analysis of GHG reductions. This CBI estimates transportation
emissions. If transportation is electrified, Avista will take on additional energy obligations
and there would be no acknowledgment of the net GHG emissions savings if considered
in isolation, but in conjunction with estimates of transportation emissions the benefit would
be seen. The challenge with this metric pertains to items within the calculation which are
outside of Avista's control and therefore only includes estimates related to either
electrification included in Avista's load forecast for transportation and changes in natural
gas usage from Avista's natural gas IRP. Currently, transportation emissions are flat
rather than increasing due to uncertainty of electric vehicle adoption. Natural gas
emissions are also nearly flat until 2045, but due to high costs to reduce emissions on
this system reductions may require additional customer incentives directed by the state
to adopt lower emitting fuels or electrification .
Figure 11.17: Washington Direct and Net Emissions
2.5 actual forecast □Direct Emissions ■Net Em issions
"' 2.0 C: 0
:E 1.5
"' C: 0 I-1.0 () ·.::
a)
:lE 0.5
<D ,-.. co er, 0 ..... N '<t I.(') <D ,-.. co er, 0 ..... N M '<t I.(') <D ,-.. co er, 0 ..... N M '<t ..... ..... ..... ..... N N N N N N N N N (") (") (") M (") M M (") (") M '<t '<t '<t '<t '<t 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N N N N N N N N N
Avista Corp 2023 Electric IRP 11-26
~
0
I ■
I.(')
'<t 0 N
Chapter 11: Washington Customer Impacts
Figure 11.18: Avista Washington Service Area Direct and Net Emissions
12.0
10.0
8.0
C/1
C:
~ 6.0
u ·;:: a, 4.0
~
C: ,Q 2.0
~ ~ ~ ~ 0 ~ N ~ ~ ~ ~ ~ ~ O ~ N M ~ ~ ~ N N N N N N N N N M M M M 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N
■Agriculture ■ Transportation
■ Waste Management ■ Electric Power Serving Idaho
■ large Sources
Future Customer Benefit Indicator Inclusion
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N
Residential & Commerical Fuels
Electric Power Serving Washington
The definition of equity and its various impact areas continues to be a topic of
conversation. CBls will continue to be measured to ensure all customers are equitably
benefitting from the clean energy transition. CBls are not intended to be static measures
and will change throughout the duration of the transition to a cleaner energy future.
Avista's CBls approved in the 2021 CEIP will remain as is until updated or modified in its
upcoming biennial CEIP update or 2025 CEIP. The CBls applicable to resource planning
will be evaluated for each IRP. While outside the planning process, resource selection
and implementation will continue to incorporate CBls as they evolve.
Avista Corp 2023 Electric IRP 11-27
Chapter 11 : Washington Customer Impacts
This Page is Intentionally Left Blank
Avista Corp 2023 Electric IRP 11-28
Chapter 12: Action Items
12. Action Items
The IRP is an ongoing and iterative process balancing regular publication timelines while
pursuing the best resource strategy for the future as the market, laws, and customer
needs evolve. The biennial publication date provides opportunities to document ongoing
improvements to the modeling and forecasting procedures and tools, as well as enhance
the process with new research as the planning environment changes. This section
provides an overview of the progress made on the 2021 action items and details of the
2023 IRP Action Plans for the 2025 IRP.
Avista's 2021 PRS provided direction and guidance for the type, timing, and size of future
resource acquisitions in 2021. The 2021 Action Plan highlighted the activities for
development in the 2023 IRP. These activities include resource acquisition processes,
regulatory filings, and analytical efforts for the next IRP.
2021 IRP Action Items
• Investigate and potentially hire a consultant to develop both a hydro and load forecast
to include a shift in climate in the Inland Northwest. This analysis would include a
range in new hydro conditions and temperatures so the Company can utilize the new
forecast for resource adequacy planning and baseline planning.
Avista expanded its planning department since the 2021 !RP, the additional staff
brought a hydrologic analytical background and was able to use Bonneville Power
Administration's regional work for Avista's needs rather than securing outside
services. Please see chapters 2 and 4, as well as the TAC 6 presentation in
Appendix A for the results of these studies.
• Investigate streamlining the IRP modeling process to integrate the resource dispatch,
resource selection and reliability verification functions.
A vista acquired PLEXOS for use in natural gas and electric planning. A vista plans
to use PLEXOS for resource valuation and its market risk evolution in the 2025
/RP. It is also possible it could replace PRiSM as the capacity expansion tool. More
details about the use of PLEXOS in the planning process will be available in the
2025 /RP process.
• Study options for the Kettle Falls CT regarding potential reductions of the natural gas
supply in winter months. The Company will investigate alternatives for this resource
including fuel storage, retirement, or relocation of the asset.
After further internal review and discussions, Avista decided to not make any
changes to Kettle Falls CT's availability. Avista will continue to evaluate changes
to the facility at a later time
• Determine how to best implement the Washington Commission 's strong
Avista Corp 2023 Electric IRP 12-1
Chapter 12: Action Items
encouragement under WAC 480-100-620 (3) regarding distribution energy resource
planning as a separate process or in conjunction with the 2025 IRP.
This /RP includes a new distributed energy resource chapter, it outlines the costs
and assumptions used in this plan. Avista is also using a consultant to examine
the resource potential for distribution energy resources (more details are available
in Chapter 5). Further, Avista's formed a Distribution Planning Advisory Group, its
first meeting was on March 29, 2023 to address how to best plan the future
distribution system. Finally, this /RP includes non-energy impacts to all resources
as part of its economic evaluation for Washington resources.
• Form an Equity Advisory Group to ensure a reduction in burdens to vulnerable
populations and highly impacted communities and to ensure benefits are equitably
distributed in the transition to clean energy in the state of Washington. This group will
provide guidance to the I RP process on ways to achieve these outcomes.
Avista formed its Equity Advisory Group (EAG) to ensure all customers are
benefitting from the transition to clean energy through the equitable distribution of
energy and nonenergy benefits and to help identify ways to reduce energy burdens
to communities and populations identified as being highly impacted by fossil fuel
pollution and climate change. Please see A vista's Washington Clean Energy page
at www.myavista. comlabout-us/washinqtons-c/ean-enerqy-future for additional
details about the EAG and how to participate.
• Avista will conduct an existing resource market potential to estimate the amount and
timing of existing resources available through 2045.
The 2023 All-Source RFP provided details about near term resource possibilities.
The RFP received 32 proposals with options from 21 developers for 11 technology
types including wind, solar, storage, natural gas, biomass, waste heat and demand
response. No additional analysis of existing resource market potential was
determined to be necessary beyond the RFP results at this time. Updates about
the 2023 RFP are available in Appendix A in the TAC 6, 8, and 9 presentations.
• Conduct further peak credit analysis to understand the reliability benefits of all
resources including demand response options with different duration and call options
of the wide range of DR program options.
Avista chose to use the WRAP numbers for peak credits or Qualifying Capacity
Credits (QCC). More refinements to the QCC numbers and their implementation
in planning will continue as this regional program develops. Additional details about
the WRAP are in the TAC 7 presentation in Appendix A and within Chapter 4.
• Avista will partner with a third-party consultant to identify non-energy impacts that
have not historically been quantified for both energy efficiency and supply side
resources.
Avista Corp 2023 Electric IRP 12-2
Chapter 12: Action Items
A vista contracted with a consultant, DNV, to develop non-energy impacts for use
in this and future IRPs. Please refer to the DNV presentation in TAC 3 in Appendix
A, the April 2023 final report on non-energy impacts in Appendix D, and how those
impacts were applied in Chapter 6. After completion of this study, numerous
additional work on nonenergy impacts can be undertaken. A vista suggest these
efforts be dealt with at state level analysis or process.
• Formalize the process for public to submit !RP-related comments and questions and
for Avista to share responses to those requests.
After discussions with the TAC and internally, Avista decided to maintain its open
process for soliciting and sharing comments and questions. This was done to
accommodate the wide variety of participants in our planning process who range
from well-funded and staffed organizations who submit detailed written requests
and questions about the process and its assumptions to individual customers who
more comfortable visiting one-on-one with the planning team.
Avista will continue to keep using this less formalized approach to help encourage
this collaborative format that includes open questions in the TAC process,
availability of the planning team and other Avista subject matter experts by email,
phone and in person based on the needs and preferences of TAC participants.
A vista welcomes suggestion and improvement of ideas to provide more
transparency to the public who wishes to engage in the process.
• Develop a transparent methodology to include pricing data and consider available
options for new renewable generation and energy storage options.
Significant amounts of data, assumptions, supplementary reports, TAC
presentations, recordings of meetings, meeting notes, and non-proprietary models
are posted on the /RP web site for review by TAC members, customers, and other
interested parties regarding this topic. This data includes the workbook used to
develop resource costs with documentation of source data and the fully functional
model used for resource decisions.
Avista Corp 2023 Electric IRP 12-3
Chapter 12: Action Items
2023 IRP Action Items
The 2023 Action Plan was developed with input from Commission Staff, Avista's
management team and members of the TAC on the analytical and other projects needed
to further development and inclusion in the 2025 IRP.
• Incorporate the results of the DER potential study where appropriate for resource
planning and load forecasting.
• Finalize the Variable Energy Resource (VER) study. This study outlines the required
reserves and cost of this energy type. Results of this study will be available for use in
the 2025 I RP.
• Study alternative load forecasting methods, including end use load forecast
considering future customer decisions on electrification. Avista expects this Action
Item will require the help of a third-party. Further, studies shall continue the range in
potential outcomes.
• Investigate the potential use of PLEXOS for portfolio optimization, transmission, and
resource valuation in future IRPs.
• Continue to work with the Western Power Pool's WRAP process to develop both
Qualifying Capacity Credits (QCC) and Planning Reserve Margins (PRM) for use in
resource planning.
• Evaluate long-duration storage opportunities and technologies, including pumped
hydro, iron-oxide, hydrogen, ammonia storage, and any other promising technology.
• Determine if the Company can estimate energy efficiency for Named Communities
versus low-income.
• Study transmission access required to access energy markets as surplus clean
energy resources are developed.
• Further discuss planning requirements for Washington's 2045 100% clean energy
goals.
Avista Corp 2023 Electric IRP 12-4