20250331Avista 2025 Natural Gas IRP.pdf

' 11
Case No.:
Avista Corp. AVU-G-25-03
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
March 31, 2025
Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd. Bldg. 8, Ste. 201-A
Boise, Idaho 83714
RE: Case No. AVU-G-25-_-Avista Utilities 2025 Natural Gas Integrated Resource Plan
Dear Ms. Noriyuki:
Avista Corporation d/b/a/Avista Utilities, hereby submits for filing with the Commission its final
2025 Natural Gas Integrated Resource Plan (IRP). Supporting documents can be found on our
website at https://myavista.com/about-us/integrated-resource-planning.
If you have any questions regarding this filing, please contact Tom Pardee at 509-495-2159.
Sincerely,
F"pu
Shawn Bonfield
Sr. Manager of Regulatory Strategy &Policy
509-434-6502
Shawn.bonfieldgavistacorp.com

2025
Integrated
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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.
Avista Corp 2025 Natural Gas IRP 2

Production Credits
Primary Gas IRP Team
Name Title Contribution
Tom Pardee Natural Gas Planning Manager IRP Core Team
Michael Brutocao Natural Gas Analyst IRP Core Team
James Gall Manager of Integrated Resource Planning IRP Core Team
John Lyons Sr. Resource Policy Analyst IRP Core Team
Lori Hermanson Sr. Power Supply Analyst IRP Core Team
Mike Hermanson Sr. Power Supply Analyst IRP Core Team
Grant Forsyth Chief Economist Load Forecast
Kim Boynton Mgr. of Energy Efficiency Analytics Energy Efficiency
Lisa McGarity Sr. Energy Efficiency Program Manager Oregon Energy Efficiency
Leona Haley Sr. Energy Efficiency Program Manager Energy Efficiency
Terrence Browne Principal Gas Planning Engineer Gas Engineering
Justin Dorr Natural Gas Resources Manager Energy Supply
Gas IRP Contributors
Name Title Contribution
Scott Kinney VP of Energy Resources and Integrated Planning Energy Supply
Mike Magruder Director of Integrated Planning and Clean Energy Integrated Planning
Kevin Holland Director of Energy Resources Energy Supply
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory Policy
Amanda Ghering Regulatory Affairs Analyst Regulatory Policy
Jared Webley Sr. Communications Manager Communications
John Gross Manager of System Planning Gas Engineering
Michael Whitby Renewable Natural Gas Program Manager Clean Energy
Contact contributors via email by placing their names in this email address format:
[e-mail]
Avista Corp 2025 Natural Gas IRP 3

Executive Summary
2025 Natural Gas IRP
Executive Summary
Avista's 2025 Natural Gas Integrated Resource Plan (IRP) identifies a Preferred
Resource Strategy (PRS) to meet system energy demand and emissions compliance in
Washington under the Climate Commitment Act (CCA) and in Oregon under the Climate
Protection Plan (CPP). Avista considers resource capacity needs on a peak day
combined with weather futures considering a warming trend and its impact on demand.
The total system load is illustrated in Figure 1 by month for 2025 to depict the seasonality
of firm customer demand on the natural gas distribution infrastructure.
Figure 1: Total System Average Daily Load (Average, Minimum and Maximum)
400,000
— Average Load
350,000 — Min Load
3001000 Max Load
2501000
200,000
150,000
1009000 '
50,000 ♦ — /
0
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Customer estimates are increasingly difficult to forecast due to the variety of rules and
codes passed by Oregon, Washington and the federal administrations. In Washington,
building codes went into effect on July 1, 2023, requiring heat pump technology for space
and water heating in all new residential and commercial buildings. This IRP maintains
these building codes in the Washington customer and demand forecasts. In November
2024, voters passed Initiative 2066 allowing for the continued use of natural gas. Line
extension programs to financially assist customers with natural gas connections have
been decreased or planned for elimination and new programs have been passed to help
customers consider more efficient equipment. With the risk of uncertainty brought into the
future state of customers and demand, 19 scenarios were developed to consider a range
Avista Corp 2025 Natural Gas IRP 4

Executive Summary
of different futures and resource selections. Avista controls sufficient gas transportation
rights, consistent with prior IRP expectations during Peak Day criteria. These protect our
customers and their structures during extreme weather.
Emissions compliance under Washington's CCA and Oregon's CPP indicates a different
story for resource need compared to historical IRPs focusing on securing transportation
rights. This IRP focuses on greenhouse gas emissions compliance program constraints
of the CCA and CPP, along with these regulations requiring planning for some transport
customers. In Figure 2, for Washington's CCA the line demonstrates the equivalent
greenhouse gas emissions from customer load and the blue area is the amount of no-
cost allowances from the program, the difference between the amounts must be secured
either using purchased allowances or emission reductions.
Figure 2: Washington Emissions Forecast rmmnnrnrl fr% r_r_A r_ap
1,400,000
No Cost Allowances
1,200,000 WA Load
1,000,000
c� 800,000
O
600,000
400,000
200,000
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O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 5

Executive Summary
In Figure 3, the chart for Oregon's CPP is similar, but Avista is covered under program
compliance instruments for expected emissions until 2029. After that, it must look to
reduce emissions to meet program requirements.
'figure 3: Oregon Emissioi„ , orecast Compared to CPP Cal
700,000
600,000 —
CPP Cap OR Load
500,000
aD
N
0 400,000
300,000
200,000
100,000
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N N N N N N N N N N N N N N N N N N N N
Both charts clearly indicate noncompliance if no measures are taken to offset emissions
or utilize other compliance options as per program rules.
Avista Corp 2025 Natural Gas IRP 6

Executive Summary
Idaho Preferred Resource Strategy
Currently the state of Idaho does not have any greenhouse gas emissions reduction
policies and requires utilities to plan for the least cost resource portfolio meeting projected
customer demand. Also, it is the only state with growth expectations in energy demand,
yet based on expected efficiency offsets does not require new resources to meet
increased loads. Based on these factors, the Idaho PRS continues to utilize natural gas
from existing access to supply basins, and our existing storage. Avista also found minimal
energy efficiency programs are economic to meet energy demand as illustrated in Figure
4. Natural gas will be acquired on a least cost basis from the available hubs. Avista's
projection of fuel acquisition considers providing reliability on days with average demand
and peak day demand based on our customers' needs. The Idaho PRS combines
available resources, demand expectations and current resource needs to select a least
cost and least risk portfolio to serve customers in a safe and reliable strategy.
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Avista Corp 2025 Natural Gas IRP 7

Executive Summary
Oregon Preferred Resource Strategy
Oregon's PRS, shown in Figure 5, has changed as compared to the 2023 IRP. Changes
adhere to the new environmental goals of the 2024 CPP and the estimated energy
demand. Natural gas continues to be used to provide the primary energy source in the
near term and continues through the forecast horizon. It will be sourced based on a least
cost supply basin, or resource, to help provide the lowest costs of energy to Oregon
customers. In 2030, Alternative resources like Renewable Natural Gas (RNG) is selected
in the first year of availability with over 1.1 million dekatherms and ramps up to over 3
million dekatherms by 2045. This resource is expected to provide both the energy and
emission offsets to the CPP. Energy Efficiency investments are expected to offset 18.5%
of demand by 2045 and are the least cost as compared to the expected costs of CPP
compliance and energy demand. Compliance instruments (CI) given to Avista from the
CPP are expected to cover emissions in the first compliance period (2025-2027), while
Community Climate Investments (CCI) are necessary beginning in 2028 through the next
decade. In the mid-term, Carbon Capture (CCUS) is selected in 2035 and increases
annually through 2045 to help offset carbon used from natural gas. These combined
resources provide the least cost and least risk selection to meet customer energy needs
and comply with CPP program requirements.
Firer- q• r)regon Prefprred RPcmirra Rfrategy
14 ■ Natural Gas CCI
i Currently Contracted RTCs Carbon Capture
N 12 ■ RNG Energy Efficiency
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N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 8

Executive Summary
Washington Preferred Resource Strategy
Washington's PRS has also changed from the 2023 IRP. The CCA program rules allow
covered entities to meet program requirements by procuring an allowance or offset.
Allowance and offset prices may drive a different PRS than the one illustrated in Figure 6
and are bound by the floor and ceiling price per year. The current prices for the floor and
ceiling in 2025 are $25.85 to $94.85, respectively. The PRS shows conventional natural
gas and energy efficiency as the primary energy source options until the end of the study
horizon in 2045. Small portions of RNG may be used as a system least cost solution in
individual years. The darker blue bars in the chart, when combined, are the CCA program
cap and would not require any additional type of program instruments. The lightest blue
bar represents natural gas as an energy source, requiring an offset or an allowance as it
is above the CCA cap. Energy efficiency is expected to provide the least cost resource
through the planning horizon. By 2045, energy efficiency is expected to offset 11% of
Washington demand. New resource costs and offsets will continually be compared to
allowance prices to select a least cost resource as costs become available. All natural
gas procured and delivered to Washington customers will continue to be based on a least
cost and risk supply basin or resource.
Figure 6: Washington Preferred Resource Strategy
30 m Allowances (Free) Allowances (Given)
Allowances (Purchased) Currently Contracted RTCs
25 RNG Energy Efficiency
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N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 9

Table of Contents
Table of Contents
Safe Harbor Statement ................................................................................................ 2
ProductionCredits ....................................................................................................... 3
Idaho Preferred Resource Strategy ............................................................................. 7
Oregon Preferred Resource Strategy .......................................................................... 8
Washington Preferred Resource Strategy ................................................................... 9
1. Introduction and Planning Environment............................................................... 21
Customers.................................................................................................................. 23
Integrated Resource Planning.................................................................................... 26
PlanningModel .......................................................................................................... 28
PlanningEnvironment................................................................................................ 29
2. Preferred Resource Strategy............................................................................... 31
CROME Planning Model............................................................................................ 32
Resource Integration.................................................................................................. 35
Demand and Deliverability Balance ........................................................................... 37
State Environmental Compliance...............................................................................41
New Resource Options and Considerations ..............................................................43
Energy Efficiency Resources .....................................................................................45
Preferred Resource Strategy (PRS)...........................................................................46
3. Demand Forecast................................................................................................ 61
DemandAreas........................................................................................................... 61
Customer Forecasts................................................................................................... 62
WeatherForecast ...................................................................................................... 72
Peak Day Design Temperature.................................................................................. 76
LoadForecast............................................................................................................ 84
ScenarioAnalysis ...................................................................................................... 85
4. Demand Side Resources..................................................................................... 89
AvoidedCost.............................................................................................................. 89
Idaho and Washington Conservation Potential Assessment...................................... 90
DemandResponse .................................................................................................. 101
Building Electrification.............................................................................................. 105
5. Gas Markets and Current Resources ................................................................ 115
Natural Gas Commodity Resources......................................................................... 115
Transportation Resources........................................................................................ 123
Storage Resources .................................................................................................. 128
Avista's Natural Gas Procurement Plan................................................................... 129
Market-Related Risks and Risk Management.......................................................... 130
Resource Utilization ................................................................................................. 131
RenewableNatural Gas........................................................................................... 134
6. Supply-Side Resource Options ......................................................................... 139
GasStorage Options ............................................................................................... 140
Capacity Options Considered Outside the IRP ........................................................ 143
Alternative Fuels Resource Supply Options............................................................. 144
Alternative Fuel Supply Price Risk........................................................................... 159
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Table of Contents
Carbon Capture Utilization and Storage (CCUS)..................................................... 164
RNG Program Considerations ................................................................................. 166
7. Policy Considerations........................................................................................ 171
Oregon..................................................................................................................... 172
Washington.............................................................................................................. 176
FederalLegislation................................................................................................... 182
8. Alternative Scenarios......................................................................................... 185
Alternate Demand Scenarios and Sensitivities ........................................................ 185
Scenario Forecasts.................................................................................................. 188
SensitivityForecasts................................................................................................ 194
Washington Climate Commitment Act Allowances ..................................................210
Oregon's Community Climate Investments.............................................................. 210
CostComparison ..................................................................................................... 211
Monte Carlo Risk Analysis .......................................................................................215
PortfolioSelection ....................................................................................................219
9. Customer Equity and Metrics ............................................................................ 223
Understanding Energy Justice .................................................................................223
Non-Energy Impacts ................................................................................................227
Customer Equity Metrics..........................................................................................233
Affordability..............................................................................................................239
10. Distribution Planning.......................................................................................... 245
Distribution System Planning ...................................................................................245
Distribution System Enhancements ......................................................................... 247
Distribution Scenario Decision-Making Process....................................................... 249
Non-Pipe Alternatives .............................................................................................. 252
PlanningResults......................................................................................................253
11. Action Plan ........................................................................................................ 257
2023 Avista Action Items.......................................................................................... 257
Oregon (OPUC-Actions) .......................................................................................... 259
2025-2026 Action Plan............................................................................................. 261
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Table of Contents
cable of Figures
Figure 1: Total System Average Daily Load (Average, Minimum and Maximum) ...........4
Figure 2: Washington Emissions Forecast Compared to CCA Cap ................................ 5
Figure 3: Oregon Emissions Forecast Compared to CPP Cap ....................................... 6
Figure 4: Idaho Preferred Resource Strategy.................................................................. 7
Figure 5: Oregon Preferred Resource Strategy............................................................... 8
Figure 6: Washington Preferred Resource Strategy........................................................ 9
Figure 1.1 : Avista's Natural Gas Service Territory ........................................................ 22
Figure 1.2: Avista's Natural Gas Customer Counts....................................................... 22
Figure1.3: Firm Customer Mix...................................................................................... 24
Figure 1.4: 2023 Percent of Firm Demand by Class...................................................... 25
Figure 1.5: Total System Average Daily Load ............................................................... 26
Figure 2.1 : CROME Idaho System Map........................................................................ 33
Figure 2.2: CROME Washington System Map.............................................................. 33
Figure 2.3: CROME Oregon System Map..................................................................... 34
Figure 2.4: Total System Average Daily Load (Average, Minimum and Maximum) ...... 35
Figure 2.5: Carbon Legislation Sensitivities .................................................................. 36
Figure 2.6: Existing Firm Transportation Resources ..................................................... 37
Figure 2.7: Average Demand - Storage & Transport Rights for February 28t" .............. 38
Figure 2.8: Average Demand - Storage & Transport Rights for December 20th ........... 39
Figure 2.9: Peak Day Demand - Storage & Transport Rights for February 28t" ............40
Figure 2.10: Peak Day Demand - Storage & Transport Rights for December 20th .......40
Figure 2.11 : Washington Emissions Forecast Compared to No Cost Allowances ........42
Figure 2.12: Oregon Emissions Forecast Compared to CPP Cap ................................42
Figure 2.13: Cumulative Demand Served by Energy Efficiency....................................46
Figure 2.14: Idaho Preferred Resource Strategy...........................................................47
Figure 2.15: Idaho Natural Gas Basin Supply ...............................................................48
Figure 2.16: Oregon Preferred Resource Strategy — Firm Customers ..........................49
Figure 2.17: Oregon Natural Gas Basin Supply — Firm Customers...............................49
Figure 2.18: Community Climate Investment Quantity — All Customers (MTCO2e)...... 51
Figure 2.19: Washington Preferred Resource Strategy — Firm Customers ................... 52
Figure 2.20: Natural Gas Basin Supply — Washington — Firm Customers..................... 52
Figure 2.21 : CCA Allowances/Offsets Quantities by Type (MTCO2e)........................... 54
Figure 2.22: Washington Preferred Resource Strategy — Transport Customers ........... 55
Figure 2.23: Oregon Preferred Resource Strategy - Transport Customers................... 55
Figure 2.24: Washington Preferred Resource Strategy —All Customers....................... 56
Figure 2.25: Oregon Preferred Resource Strategy - All Customers .............................. 57
Figure 2.26: System Preferred Resource Strategy - All Customers .............................. 57
Figure 2.27: PRS Changes to Meet Carbon Neutral Goal of 100% by 2045................. 59
Figure 3.1 : Residential Customer Forecast................................................................... 62
Figure 3.2: Commercial Customer Forecast.................................................................. 63
Figure 3.3: Industrial Customer Forecast...................................................................... 63
Figure 3.4: LoadmapTM Inputs and Sources.................................................................. 64
Figure 3.5: Idaho Demand by End Use ......................................................................... 65
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Figure 3.6: Oregon Demand by End Use ...................................................................... 65
Figure 3.7: Washington Demand by End Use ............................................................... 66
Figure 3.8: System Demand (Firm Customers)............................................................. 66
Figure 3.9: Idaho Residential - Load Reduction Occurring Naturally............................. 67
Figure 3.10: Oregon Residential - Load Reduction Occurring Naturally........................ 68
Figure 3.11 : Washington Residential - Load Reduction Occurring Naturally................. 68
Figure 3.12: Idaho Commercial - Load Reduction Occurring Naturally ......................... 69
Figure 3.13: Oregon Commercial - Load Reduction Occurring Naturally ...................... 69
Figure 3.14: Washington Commercial - Load Reduction Occurring Naturally ............... 70
Figure 3.15: Residential Customers Energy Intensity per Customer in Washington ..... 71
Figure 3.16: Commercial Energy Intensity (Therms/Sgft) in Washington...................... 71
Figure 3.17: Monthly Demand of Transport Customers (MMBTU)................................ 72
Figure 3.18: 20 Year Rolling Average by Weather Station ............................................ 73
Figure 3.19: RCP 4.5 Blended with 20 Year Historic Temperatures ............................. 75
Figure 3.20: 20-Year Decrease of HDDs by Planning Region....................................... 76
Figure 3.21 : Medford Weather Station - Weather Planning Standard Comparison ...... 77
Figure 3.22: Spokane Historical Temperature Distribution ............................................ 78
Figure 3.23: Medford Historical Temperatures.............................................................. 79
Figure 3.24: La Grande Historical Temperatures .......................................................... 79
Figure 3.25: Klamath Falls Historical Temperatures...................................................... 80
Figure 3.26: Roseburg Historical Temperatures............................................................ 80
Figure 3.27: Frequency of Annual HDDs (2026-2045) - Spokane................................ 82
Figure 3.28: Frequency of Annual HDDs (2026-2045) - Medford................................. 82
Figure 3.29: Frequency of Annual HDDs (2026-2045) - Roseburg............................... 83
Figure 3.30: Frequency of Annual HDDs (2026-2045) - Klamath Falls ........................ 83
Figure 3.31 : Frequency of Annual HDDs (2026-2045) - La Grande ............................. 84
Figure 3.32: System Load Forecast by Scenario/Sensitivity ......................................... 87
Figure 4.1 : Residential Winter Avoided Cost (By Jurisdiction) ...................................... 90
Figure 4.2: Washington Residential - Energy Efficiency Savings and Costs................. 92
Figure 4.3: Washington Commercial - Energy Efficiency Savings and Costs................ 93
Figure 4.4: Washington Industrial - Energy Efficiency Savings and Costs .................... 93
Figure 4.5: Washington Transport - Energy Efficiency Savings and Costs ................... 94
Figure 4.6: Idaho Residential - Energy Efficiency Savings and Costs........................... 95
Figure 4.7: Idaho Commercial - Energy Efficiency Savings and Costs ......................... 95
Figure 4.8: Idaho Industrial - Energy Efficiency Savings and Costs .............................. 96
Figure 4.9: Oregon Residential Energy Efficiency Savings and Costs .......................... 98
Figure 4.10: Oregon Commercial Energy Efficiency Savings and Costs....................... 99
Figure 4.11 : Oregon Industrial Energy Efficiency Savings and Costs ........................... 99
Figure 4.12: Oregon Transport Energy Efficiency Savings and Costs......................... 100
Figure 4.13: 20-Year Cumulative Savings Potential by Type (Dth) ............................. 101
Figure 4.14: Program Characterization Process ......................................................... 102
Figure 4.15: Climate Zone Map................................................................................... 106
Figure 4.16: Modeled Heat Pump Efficiency ............................................................... 107
Figure 4.17: Electric and Gas Rate Comparison - WA Residential............................. 108
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Table of Contents
Figure 4.18: Washington Residential Energy Demand - kWh ..................................... 109
Figure 4.19: Electric Rate Assumption by Area by Class (Nominal $)......................... 111
Figure 4.20: Conversion and Energy Costs - Space Heat WA Residential (2026 $) ... 112
Figure 4.21 : Space Heat Levelized Costs by Area for Residential Electrification........ 113
Figure 4.22: Water Heat Levelized Costs by Area for Residential Electrification ........ 113
Figure 4.23: Space Heat Levelized Costs by Area for Commercial Electrification ...... 114
Figure 4.24: Water Heat Levelized Costs by Area for Commercial Electrification ....... 114
Figure 5.1 : Average Annual Index Prices.................................................................... 117
Figure 5.2: Henry Hub Forecasted Price Study Forecasts (Nominal $/Dekatherm) .... 119
Figure 5.3: Expected Price with Allocated Price Forecast........................................... 120
Figure 5.4: Henry Hub Prices for Low/ Expected/ High Price Scenarios ..................... 121
Figure 5.5: Regional and Henry Hub Pricing Comparison........................................... 122
Figure 5.6: AECO - $ per Dth (500 Draws).................................................................. 122
Figure 5.7: Regional Pipeline and Storage Capacity................................................... 124
Figure 5.8: Direct-Connect Pipelines........................................................................... 126
Figure 5.9: Avista Contracted RTCs Total Volume...................................................... 135
Figure 5.10: Avista Average Expected Price of RTCs Under Contract........................ 136
Figure 5.11 : Participants by State ............................................................................... 137
Figure 6.1 : Demand and Resource Options................................................................ 139
Figure 6.2: Propane Storage Fixed and Variable Costs - Dth per Day (nominal $)..... 141
Figure 6.3: LNG Storage Fixed and Variable Priced — Dth per Day (nominal $) ......... 142
Figure 6.4: Modeled Volumes Compared to Technical Potential Volumes.................. 146
Figure 6.5: Percentage of Total Volumetric Availability by Source .............................. 147
Figure 6.6: Annual Modeled Volumes by Alternative Fuel Type.................................. 147
Figure 6.7: Higher Cost RNG Price by Source (nominal $) ......................................... 150
Figure 6.8: Lower Cost RNG Price by Source (nominal $).......................................... 150
Figure 6.9: RNG Modeled Resource Potential Volumes ............................................. 151
Figure 6.10: Higher Cost RTCs Price by Source (nominal $) ...................................... 152
Figure 6.11 : Lower Cost RTCs Price by Source (nominal $)....................................... 152
Figure 6.12: Hydrogen Cost Estimates........................................................................ 154
Figure 6.13: Hydrogen Daily Modeled Volumes.......................................................... 155
Figure 6.14: Synthetic Methane Cost Estimates ......................................................... 158
Figure 6.15: Synthetic Methane Daily Modeled Volumes............................................ 158
Figure 6.16: RNG Landfill RNG (LFG 5) - $ per Dth (500 Draws) ............................... 159
Figure 6.17: Dairy RNG (AM 5) - $ per Dth (500 Draws)............................................. 160
Figure 6.18: Food Waste RNG (FW 3) - $ per Dth (500 Draws).................................. 160
Figure 6.19: Wastewater Treatment RNG (WW 5) - $ per Dth (500 Draws)................ 161
Figure 6.20: Hydrogen (GreenH2-Solar + Electrolysis1) - $ per Dth (500 Draws)....... 161
Figure 6.21 : Synthetic Methane (Biomass 3) - $ per Dth (500 Draws) ........................ 162
Figure 6.22. Options for CO2 Utilization (via NETL) .................................................... 165
Figure 6.23: CCUS Fixed and Variable Priced per Dth (nominal $) ............................ 165
Figure 6.24: CCUS Volumes Modeled MTCO2e......................................................... 166
Figure 7.1 : Resource Planning Balancing Act............................................................. 171
Figure 7.2: Oregon Customers Annual Emissions Compliance Cap Comparison....... 173
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Table of Contents
Figure 7.3: Maximum Available CCI Compared to the Expected Load........................ 174
Figure 7.4: Community Climate Investment ($ per MTCO2e) ..................................... 174
Figure 7.5: Expected Load Forecast Emissions Compared to CPP Emissions Target 175
Figure 7.6: Climate Commitment Act Coverage .......................................................... 177
Figure 7.7: Expected Load Forecast Emissions Compared to CCA Emissions Target 178
Figure 7.8: Expected CCA Allowance Prices .............................................................. 179
Figure 7.9: Social Cost of Carbon at 2.5% Modeled Costs ......................................... 181
Figure 8.1 : System Annual Demand Scenarios........................................................... 188
Figure 8.2: Preferred Resource Strategy (MTCO2e)................................................... 189
Figure 8.3: No Climate Programs (MTCO2e).............................................................. 190
Figure 8.4: Social Cost of Greenhouse Gas (MTCO2e).............................................. 191
Figure 8.5: Diversified Portfolio Resource Selection (MTCO2e) ................................. 192
Figure 8.6: Resiliency (MTCO2e)................................................................................ 193
Figure 8.7: Average Case (MTCO2e).......................................................................... 195
Figure 8.8: High Alternative Fuel Costs (MTCO2e)..................................................... 196
Figure 8.9: High CCA Allowance Pricing (MTCO2e) ................................................... 197
Figure 8.10: High Electrification (MTCO2e)................................................................. 199
Figure 8.11 : High Growth on the Gas System (MTCO2e)........................................... 200
Figure 8.12: Hybrid Heating (MTCO2e).......................................................................201
Figure 8.13: High Natural Gas Prices (MTCO2e)........................................................202
Figure 8.14: 1-2066 (MTCO2e)....................................................................................203
Figure 8.15: Low Alternative Fuel Costs (MTCO2e)....................................................204
Figure 8.16: Low Natural Gas Use (MTCO2e) ............................................................205
Figure 8.17: RCP 6.5 Weather (MTCO2e) ..................................................................206
Figure 8.18: RCP 8.5 Weather (MTCO2e) ..................................................................207
Figure 8.19: No Purchased Allowances After 2030 (MTCO2e)...................................208
Figure 8.20: No Growth (MTCO2e).............................................................................209
Figure 8.21 : Annual Allowance Demand by Case — Washington CCA........................ 210
Figure 8.22: CCI Demand by Case — Oregon CPP ..................................................... 211
Figure 8.23: PRS Alternative Scenario Cost Comparison ........................................... 212
Figure 8.24: All Scenarios and Sensitivities 20-Year Costs (2026$) ........................... 212
Figure 8.25: PRS — Millions (500 Draws) ....................................................................216
Figure 8.26: Diversified Portfolio — Millions (500 Draws).............................................216
Figure 8.27: No Climate Programs — Millions (500 Draws)..........................................217
Figure 8.28: Resiliency — 1,000 of $ (500 Draws) ....................................................... 217
Figure 8.29: Social Cost of Carbon — $ Millions (500 Draws)...................................... 218
Figure 8.30: Scenario - Monte Carlo Results Comparison - $ Millions ........................ 218
Figure 8.31 : Optimized Portfolio — $ Millions (500 Draws)...........................................219
Figure 8.32: Annual Levelized Costs and Risks - All Portfolios...................................221
Figure 9.1 : Social Cost of Carbon ...............................................................................228
Figure 9.2: Customer Safety Impact............................................................................230
Figure 9.3: CO2 Cost per Dth (Nominal $)...................................................................231
Figure 9.4: CH4 Cost per Dth (Nominal $)...................................................................231
Figure 9.5: N2O Cost per Dth (Nominal $)...................................................................232
Avista Corp 2025 Natural Gas IRP 15

Table of Contents
Figure 9.6: Washington Direct CO2 Emissions............................................................234
Figure 9.7: Oregon Direct CO2 Emissions................................................................... 234
Figure 9.8: Washington Direct N2O Emissions............................................................ 235
Figure 9.9: Oregon Direct N2O Emissions................................................................... 235
Figure 9.10: Washington Direct CH4 Emissions .......................................................... 236
Figure 9.11 : Oregon Direct CH4 Emissions................................................................. 236
Figure 9.12: Oregon Induced Economic Growth from RNG ........................................ 237
Figure 9.13: Oregon Induced Job Creation from RNG/Energy Efficiency.................... 238
Figure 9.14: Washington Induced Job Creation from Energy Efficiency...................... 238
Figure 9.15: Example Space Heating Winter Month Bill by Jurisdiction (80 therms)... 240
Figure 9.16: Example Space Heating Annual Bill by Jurisdiction (465 therms) ........... 241
Figure 9.17: OR Customers with Excess Energy Burden............................................ 242
Figure 9.18: WA Customers with Excess Energy Burden ........................................... 243
Figure 9.19: OR Customers with Excess Energy Burden (Before Energy Assistance)244
Figure 9.20: WA Customers with Excess Energy Burden (Before Energy Assistance)244
Figure 10.1 : Distribution Scenario Process .................................................................251
Avista Corp 2025 Natural Gas IRP 16

Table of Contents
Table of Tablet
Table 1.1: TAC Member Participation ........................................................................... 27
Table 1.2: Summary of Changes from the 2023 IRP..................................................... 30
Table 2.1: New Supply-Side and Demand-Side Resource Options ..............................43
Table 2.2: New Resources Availability..........................................................................43
Table 2.3: Average Daily Resource Quantities by Year ................................................ 50
Table 2.4: Average Daily Resource Quantities by Year - Washington ......................... 53
Table 3.1: Geographic Demand Classifications ............................................................ 61
Table 3.2: Annual Average Demand Change by State (2026-2045) ............................. 70
Table 3.3: Comparison of Temperature Increases by RCP........................................... 74
Table 3.4: Peak Day Design Temperature .................................................................... 77
Table 3.5: Example of Monte Carlo Weather Inputs - Spokane.................................... 81
Table 3.6: Load Forecast (Thousand Dekatherms)....................................................... 84
Table 3.7: Peak Day Load Forecast by Area (Thousand Dekatherms) ......................... 85
Table 3.8: Demand Scenarios and Sensitivities............................................................ 86
Table 4.1: Washington 2026-2027 Conservation Target by Sector, (Dth)..................... 96
Table 4.2: Idaho 2026-2027 Conservation Target by Sector, (Dth)............................... 97
Table 4.3: NGDR Program Options by Market Segment............................................. 102
Table 4.4: NGDR Program Winter Peak Reduction (Dth)............................................ 104
Table 4.5: System Program Cost (Capital and O&M).................................................. 104
Table 4.6: Estimated Conversion Costs (Dth) - Real 2026$....................................... 110
Table 5.1 : Price Blend Methodology........................................................................... 120
Table 5.2 : Annual Natural Gas Price by Basin (Nominal $)........................................ 123
Table 5.3: Firm Transportation Resources Contracted (Dth/Day) ............................... 125
Table 6.1: Volumetric Breakout by LDC in the Northwest ........................................... 146
Table 6.2: Carbon Intensity (Ibs per mmbtu) ............................................................... 148
Table 6.3: Renewable Natural Gas Options................................................................ 149
Table 6.4: Production Types of Hydrogen: .................................................................. 153
Table 6.5: Electrolyzer Facility Production Cost Inputs ............................................... 155
Table 6.6: Green H2-Biogenic CO2 ............................................................................. 157
Table 6.7: Alternative Fuels Costs per Dth (Nominal $) .............................................. 163
Table 8.1: IRP Scenarios ............................................................................................ 186
Table 8.2: IRP Sensitivities ......................................................................................... 186
Table 8.3: Scenario and Sensitivity Input Guide.......................................................... 187
Table 8.4: Residential Customer Price Impact ($ per dekatherm)............................... 213
Table 8.5: Commercial Customer Price Impact ($ per dekatherm) ............................. 213
Table 8.6: Industrial Customer Price Impact ($ per dekatherm) .................................. 214
Table 8.7: Transport Only Customer Price Impact ($ per dekatherm)......................... 214
Table 8.8: Estimated Residential Customer Cost Impact ($per Therm) ...................... 215
Table 9.1: Avista Specific LDC Natural Gas Emissions............................................... 229
Table 9.2: Global Warming Potential (GWP) in CO2 Equivalent.................................. 229
Table 10.1: High Pressure - Distribution Planning Capital Projects............................. 255
Table 10.2: City Gate Station Upgrades...................................................................... 255
Avista Corp 2025 Natural Gas IRP 17

Chapter 1: Introduction and Planning Environment
Acronym List
AEG: Applied Energy Group
AMI: Automated Meter Infrastructure
ATR: Autothermal Reforming
BCF: Billion Cubic Feet
BCP: Biennial Conservation Plan
BTU: British Thermal Unit
CCA: Climate Commitment Act
CBO: Community Based Organizations
CCA: Climate Commitment Act
CC&B: Customer Care and Billing
CCI: Community Climate Investments
CCUS: Carbon Capture Utilization and Storage
CDD: Colling Degree Day
CETA: Clean Energy Transformation Act
CBI: Customer Benefit Indicator
CH4: Methane
CPA: Conservation Potential Assessment
CPI: Consumer Price Index
CPP: Climate Protection Plan
CNG: Compressed Natural Gas
CROME: Comprehensive Resource Optimization Model in Excel
DOE: Department of Energy
DOH: Department of Health
DLC: Direct Load Control
DNG: Direct Natural Gas
DR: Demand Response
DSM: Demand Side Management
DTh: Dekatherm
EAG: Equity Advisory Group
EAAG: Energy Assistance Advisory Group
EEAG: Energy Efficiency Advisory Group
EITE: Emission Intensive and Trade Exposed
ETO: Energy Trust of Oregon
FERC: Federal Energy Regulatory Commission
GTN: TC Energy Pipeline
H2: Hydrogen
HDD: Heating Degree Day
HG: Mercury
IAQ: Indoor Air Quality
ICF: ICF Consulting
IOU: Investor-Owned Utility
IP: Industrial Production Index of the U.S. Federal Reserve
IPCC: Intergovernmental Panel on Climate Change
Avista Corp 2025 Natural Gas IRP 18

Chapter 1: Introduction and Planning Environment
IRP: Integrated Resource Plan
kWh: Kilowatt-hour(s)
GDP: Gross Domestic Product
GHG: Greenhouse Gas
GWh: Gigawatt-hour(s)
LCFS: Low Carbon Fuel Standard
LDC: Local Distribution Center
LFG: Landfill Gas
MACA: Multivariate Adaptive Constructed Analogs
MIP: Mixed Integer Program
MSA: Metropolitan Statistical Area
MW: Megawatt(s)
MWh: Megawatt-hour(s)
N2O: Nitrous Oxide
NDR: Natural Gas Demand Response
NEEA: Northwest Energy Efficiency Alliance
NEI: Non-Energy Impact
NOAA: National Oceanic and Atmospheric Administration
NOx: Nitrous Oxide
NREL: National Renewable Energy Laboratory
OPUC: Oregon Public Utility Commission
O&M: Operations and Maintenance
PGA: Purchase Gas Adjustment
PSE: Puget Sound Energy
PRS: Preferred Resource Strategy
RCP: Representative Concentration Pathway
RCW: Revised Code of Washington
RFP: Request for Proposal
RIN: Renewable Identification Number
RNG: Renewable Natural Gas
RTC: Renewable Thermal Credit
SBCC: State Building Code Council
SM: Synthetic Methane
SMR: Steam Methane Reforming
SO2: Sulfur Dioxide
TAC: Technical Advisory Committee
TRC: Total Resource Cost
UCT: Utility Cost Test
UEC: Unit Energy Consumption
UPC: Use Per Customer
UTC: Washington Utilities and Transportation Commission
WAC: Washington Administrative Code
WCSB: Western Canadian Sedimentary Basin
WWTP: Waste-Water Treatment Plant
Avista Corp 2025 Natural Gas IRP 19

Chapter 1: Introduction and Planning Environment
This Page is Intentionally Left Blank
Avista Corp 2025 Natural Gas IRP 20

Chapter 1: Introduction and Planning Environment
1 . Introduction and Planning Environment
Section Highlights:
• A total of 11 Technical Advisory Committee (TAC) meetings were held.
• TAC participation included a representation from over 24 organizations and the public.
• A customer focused public meeting was held on March 5, 2025.
• Avista is using a new model for the 2025 IRP (CROME).
Avista is an investor-owned utility involved in the production, transmission, and
distribution of natural gas and electricity, as well as other energy-related businesses.
Avista, founded in 1889 as Washington Water Power, has been providing reliable,
efficient, and reasonably priced energy to customers for over 135 years. Avista entered
the natural gas business with the purchase of Spokane Natural Gas Company in 1958.
In 1970, it expanded into natural gas storage with Washington Natural Gas (now Puget
Sound Energy) and El Paso Natural Gas (its interest subsequently purchased by
Northwest Pipeline) to develop the Jackson Prairie natural gas underground storage
facility located near Chehalis, Washington. In 1991, Avista added 63,000 customers with
the acquisition of CP National Corporation's Oregon and California properties. Avista sold
the California properties and its 18,000 South Lake Tahoe customers to Southwest Gas
in 2005. Figure 1.1 shows where Avista currently provides natural gas service to
approximately 377,000 customers in eastern Washington, northern Idaho, and several
communities in northeast and southwest Oregon. Figure 1.2 shows the number of firm
natural gas customers by state.
Avista Corp 2025 Natural Gas IRP 21

Chapter 1: Introduction and Planning Environment
Figure 1.1: Avista's Natural Gas Service Territory
WESTERN
CANADIAN
SEDIMENTARY
BASIN
Avista Calgary
AECO
Natural Vancouver
Service 1 •
a � sw,.i.nFlm aiiiyib
Fields,Gas
❑Kii l-
Trading •
Seattle Spokane
• Major
Pipelines
• - Othello•
Scmeeld •Grangevllle
•
Portland •la Grande
Avista Service Territory •
Williams-Northwest Pipeline ■
Enbridge-Westcoast ■
TCEnergy-GTN ■ •Rois.
•Roseburg
TCEnergy—Foothills ■ Medford ROCKIES
TCEnergy—Nova ■ Grants Pass• • • Klamath Falls BASIN
M.11in
Kinder Morgan-Ruby ■ Wyoming Pool
Jackson Prairie Storage Project
Trading Hubs O
Figure 1.2: Avista's Natural Gas Customer Counts
Transport. 81
Corn
t<ther, 278
328,632
Industrial, 192
L AdlibA Interuptible, 5
Avista's natural gas operations covers 30,000 square miles, with a population of 1.6
million people. Avista manages its natural gas operation through the North and South
operating divisions:
Avista Corp 2025 Natural Gas IRP 22

Chapter 1: Introduction and Planning Environment
• The North Division includes Avista's eastern Washington and northern Idaho
service areas. It includes urban areas, farms, timberlands, and the Coeur d'Alene
mining district. Spokane is the largest metropolitan area with a regional population
of approximately 551,0001 followed by the Lewiston, Idaho/Clarkston,
Washington, and Coeur d'Alene, Idaho, areas. The North Division has about 75
miles of natural gas transmission pipeline and 6,300 miles in the distribution
system in Washington and 3,700 miles in Idaho. The North Division receives
natural gas at more than 40 connection points along interstate pipelines for
distribution to over 260,000 customers.
• The South Division serves four counties in southern Oregon and one county in
eastern Oregon. The combined population of these areas is over 585,000
residents. The South Division includes urban areas, farms, and timberlands. The
Medford, Ashland and Grants Pass areas, located in Jackson and Josephine
Counties, are the largest part of this division with a regional population of
approximately 312,000. The South Division consists of approximately 15 miles of
natural gas transmission main and 3,900 miles of distribution pipelines. Avista
receives natural gas at more than 20 connection points along interstate pipelines
and distributes it to nearly 102,000 customers.
Customers
Avista provides natural gas services to both core and transportation-only customer
classes. Core or retail customers purchase natural gas directly from Avista with delivery
to their home or business at a bundled rate. Core customers on firm rate schedules are
entitled to receive any volume of natural gas they require. Some core customers are on
interruptible rate schedules. These customers pay a lower rate than firm customers
because their service can be interrupted. Interruptible customers are not considered in
peak day IRP planning.
Transportation-only customers purchase natural gas from third parties who deliver the
purchased gas to our distribution system. Avista delivers this natural gas to its customers
charging a distribution rate only. Avista can interrupt the delivery service when following
the priority of service tariff. However, new environmental programs in Oregon and
Washington include Avista interruptible and transport customers within our compliance
requirements. These environmental programs are discussed in -haDter with resource
selection in :haDter . Further, changes in policy ( aater () may impact a customer's
decision to remain in a specific class like transport due to effects of environmental
programs. In the event Avista is required to procure alternative fuels to meet climate
https://www.census.gov/quickfacts/fact/table/spokanecountywashington,WA/PST045221
Avista Corp 2025 Natural Gas IRP 23

Chapter 1: Introduction and Planning Environment
program requirements it would change the meaning of being a transportation supplier and
place these users in a commercial or industrial class
Avista's core or retail customers include residential, commercial, and industrial
categories. Most of Avista's customers are residential, followed by commercial and
relatively few industrial accounts (Figure 1.3).
Figure 1.3: Firm Customer Mix
180.000
160,000
140.000
0 120,000
100,000
E
� 80,000
L
jL 60,000
w
0 40,000
4
20,000
0
WA ID OR
Ind 86 59 47
Com 14.777 9,203 11.369
Res 155.816 81.772 91.044
The customer mix is found mostly in the residential and commercial accounts on an
annual volume basis (Figure 1.4). The volume consumed by core industrial customers is
not significant to the total, partly because most industrial customers in Avista's service
territories are transportation-only customers. These customers, however, will still require
a compliance mechanism or alternative fuels to meet emissions targets if their emissions
are lower than the environmental program requirements as discussed in ;hapter . .
Avista Corp 2025 Natural Gas IRP 24

Chapter 1: Introduction and Planning Environment
Figure 1 A 2023 Percent of Firm Demand by Class
OR Ind, 0.1%
ID Ind, 0.5% OR Com,
OR Res, 14.3% 9.2%
1 D Com, 9.1%
WA Res,
I D Res, 15.8%
WA Com,
WA Ind, 0.7% 19.3%
The seasonal nature of weather in the Pacific Northwest can drastically alter the amount
of energy demanded from the natural gas system for the 2024-2025 PGA year (Figure
1.5). Industrial demand, which is typically not weather sensitive, has very little seasonality.
However, the La Grande service territory has several industrially classified agricultural
processing facilities producing a late summer seasonal demand spike.
Avista Corp 2025 Natural Gas IRP 25

Chapter 1: Introduction and Planning Environment
Figure 1.5: Total System Average Daily Load
400,000
— Average Load
3509000 — Min Load
300,000 — Max Load
2509000
2009000
o �
1509000
100,000
509000 — *Aft waft
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Integrated Resource Planning
Avista's IRP involves a comprehensive analytical process to ensure our core firm
customers can receive long-term reliable natural gas service in extreme weather. The IRP
evaluates, identifies, and plans for the acquisition of an optimal combination of existing
and future resources using expected costs and associated risks to meet state
environmental policies, average daily and peak-day demand delivery requirements over
a 20-year planning horizon.
Purpose of the Natural Gas IRP
• Provides a comprehensive long-range planning tool;
• Fully integrates forecasted requirements with existing and potential resources;
• Determines the most cost-effective and risk-adjusted means for meeting future
demand requirements; and
• Meets Washington, Idaho, and Oregon regulations, commission orders,
environmental programs, and other applicable guidelines.
Avista's IRP Process Considerations
• Customer growth and expected usage;
• Weather planning standard;
• Weather futures;
Avista Corp 2025 Natural Gas IRP 26

Chapter 1: Introduction and Planning Environment
• Energy Efficiency opportunities;
• Existing and potential supply-side resource options;
• Current and known legislation/regulation;
• Greenhouse gas emissions reductions and compliance mechanisms;
• Risk; and
• Least-cost mix of supply and conservation.
Public Participation
Avista's Technical Advisory Committee (TAC) members play a key role and have a
significant impact in developing the IRP. TAC members include Commission staff, peer
utilities, government agencies, and other interested parties. TAC members provide input
on modeling, planning assumptions, and the general direction of the planning process.
Avista sponsored eleven public TAC meetings to facilitate stakeholder involvement in the
2025 IRP. The first meeting was convened in February 2024 and the last meeting
occurred in January 2025. Each meeting was on-line and approximately 2 hours in length
to make meetings more accessible and included a broad spectrum of interested parties.
The TAC meetings focused on specific planning topics, reviewing the progress of
planning activities, and soliciting input on IRP development and results. Avista
appreciates the time and effort TAC members contributed to the IRP process as they
provided valuable input through their participation. A list of organizations participating in
at least one TAC meeting can be found in Table 1.1.
Table 1.1: TAC Member Participation
Cascade Natural Gas Northwest Energy Coalition Oregon Public Utility
Commission
Fortis Northwest Natural Gas Alliance of Western Energy
Consumers
Idaho Public Utilities Biomethane, LLC Washington State Office of the
Commission Attorney General
Northwest Gas Association Washington Utilities and Citizens Utility Board of Oregon
Transportation Commission
Interested Public Parties Northwest Power and Energy Trust of Oregon
Conservation Council
Puget Sound Energy Energy Strategies Oregon Department of Energy
Lewis and Clark Law Eastern Washington University Applied Energy Group
School
Oregon Department of Sierra Club City of Spokane
Energy
Public Meetings
A public meeting was held on March 5, 2025 at noon lasting an hour. In this meeting,
Avista reviewed the preferred resources selected in the natural gas IRP to meet energy
demand and/or energy policy compliance. An email was sent to TAC members and
Avista Corp 2025 Natural Gas IRP 27

Chapter 1: Introduction and Planning Environment
customers in all jurisdictions informing them of the opportunity to participate and provide
feedback. During the public meeting, summary level results byjurisdiction were presented
to the participants. The public meeting structure is important as one does not have to be
versed in the technical topics discussed in TAC meetings to participate. It also provides
direct access to Avista subject matter experts to ask questions and provide feedback
about topics most important to each customer. These comments and questions can be
found in Appendix 1 and the recordings for each session are available on the Avista IRP
website.2
Regulatory Requirement:
Avista submits a natural gas IRP to the public utility commissions in Idaho, Oregon, and
Washington every two years as required by state law or rule. There is a statutory
obligation to provide reliable natural gas services to customers at rates, terms, and
conditions that are fair,just, reasonable, and sufficient. Avista regards the IRP as a means
for identifying methodologies and processes for the evaluation of potential resource
options and as a process to establish an Action Plan for resource decisions. Ongoing
investigation, analysis, and research may result in determining alternative resources to
be more cost effective than resources reviewed and selected in this IRP. Avista will
continue to review and refine its understanding of resource options and will act to secure
these risk-adjusted, least-cost options when appropriate.
Planning Model
New to the 2025 IRP, Avista used an internally developed planning model named
CROME (Comprehensive Resource Optimization Model in Excel) to perform
comprehensive natural gas supply planning and analysis in place of the prior software
from Energy Exemplar named PLEXOS® and ABB's SENDOUT. At a lower cost to
customers, CROME provides the flexibility to properly model unique physical and periodic
constraints necessitated by new resources and environmental compliance regulations.
This model uses a nodal and zonal analysis with:
• Customer growth, energy intensity and usage patterns to form demand forecasts
net of energy efficiency savings as provided by AEG and ETO;
• Future weather forecasts;
• Electrification and demand response options;
• Existing and potential natural gas and alternative fuel supply availability and
pricing;
• Existing and potential transportation and storage options and associated costs;
• Existing and potential environmental compliance mechanism supply availability
and pricing; and
• Revenue requirements on all new asset additions.
2 https://www.myavista.com/about-us/integrated-resource-planning
Avista Corp 2025 Natural Gas IRP 28

Chapter 1: Introduction and Planning Environment
Avista incorporated stochastic modeling in CROME to measure risk around weather,
supply and price uncertainty. Some examples of the types of stochastic analysis provided
include:
• Price and weather probability distributions;
• Volumetric availability of alternative fuels and compliance mechanisms;
• Probability distributions of costs (i.e., system and commodity costs); and
• Resource mix (optimally sizing a contract or asset level of competing resources).
These computer-based planning tools were used to develop the optimal least-cost, risk-
adjusted 20-year resource portfolio plan to serve customers.
Planning Environment
Even though Avista publishes an IRP every two years, the planning process is ongoing
with new information and industry related developments occurring regularly. In normal
circumstances, the process can become complex as underlying assumptions evolve,
impacting previously completed analyses. Widespread agreement on the availability of
shale gas and the ability to produce it at lower prices has increased interest in the use of
natural gas for LNG and exports to Mexico as well as for industrial uses across North
America. Policies meant to decrease the use of natural gas are outlined in Chapter 5 and
represent one of the most prominent risks evaluated in this IRP; however, there is
uncertainty around the timing and size of the impacts of these policy decisions.
IRP Planning Strategy
Planning for an uncertain future requires robust analysis encompassing a wide range of
possibilities. Avista has determined the planning approach needs to:
• Adhere to new environmental laws and policies in Oregon and Washington;
• Recognize historical trends may be fundamentally altered;
• Critically review all modeling assumptions;
• Pursue a spectrum of scenarios and sensitivities;
• Develop a flexible analytical framework to accommodate changes; and
• Maintain a long-term perspective combined with a near-term resource plan.
With these objectives in mind, Avista developed a strategy encompassing all required
planning criteria. This produced an IRP that effectively analyzes risks and resource
options, which sufficiently ensures customers will receive safe and reliable energy
delivery services with the best-risk, least-cost long-term solutions. The following chart
summarizes significant changes from the 2023 IRP (Table 1.2).
Avista Corp 2025 Natural Gas IRP 29

Chapter 1: Introduction and Planning Environment
Table 1.2: Summary of Changes from the 2023 IRP
Subject Area 2025 Gas IRP 2023 Gas IRP
Demand System Growth 0.68% 1.10%
Demand Weather and Trended coldest on record to 99% probability of a
Design Day Peak the % of overall weather future temperature occurring based
reduction in heating degree on the coldest temperature
days by 2045 each year for the past 30
years combined with weather
forecasted temperatures and
trended from the historic peak
day
Demand Energy Efficiency ID: 6 Million Therms ID: 12.7 Million Therms
Demand Energy Efficiency OR: 17.6 Million Therms OR: 16.1 Million Therms
Demand Energy Efficiency WA: 19.5 Million Therms WA: 25.3 Million Therms
Demand Energy Efficiency ID: No Carbon Cost ID: National Carbon Tax
beginning in 2030 ($12.00 -
$62.08per MTCO2e
Demand Energy Efficiency WA: Social Cost of Carbon @ WA: Social Cost of Carbon @
2.5% discount rate ($109 - 2.5% discount rate ($92.68 -
$215) per MTCO2e $185.07) per MTCO2e
Supply Natural Gas Price A higher price curve at$4.94/ A price curve at$4.50/ Dth
Forecast Dth levelized cost in real 2024 levelized cost in real 2022 US
US $ $
Policy Program CCA (WA): $44 -$117 per CCA (WA): $46 - $83 per
Instruments for Allowance (MTCO2e) Allowance (MTCO2e)
Compliance
Policy Program CPP (OR): Cost of compliance OR: Cost of Carbon ($92.68 -
Instruments for to 2025 CPP $185.07) per MTCO2e
Compliance $141 - $241 per MTCO2e
Policy CPP 2025 Climate Protection Plan 2022 Climate Protection Plan
CPP - Oregon CPP - Oregon
Avista Corp 2025 Natural Gas IRP 30

Chapter 2: Preferred Resource Strategy
2. Preferred Resource Strategy
Section Highlights:
• Energy Efficiency reduces demand by over 4.35 million dekatherms by 2045.
• No new fuel transportation is required to meet firm customer loads.
• Idaho's preferred resource continues to be natural gas as it is the least cost
resource.
• Renewable natural gas is needed by 2030 along with over 112,000 CCIs to meet
Oregon's CPP requirements.
• To meet Washington's CCA - the lowest cost option is to purchase allowances for
compliance.
• Avista is considering Liquefied Natural Gas Storage to increase resiliency of the
system.
This chapter combines the previously discussed IRP components used to derive a 20-
year resource plan to meet Avista's resource deficiencies and state environmental policy
objectives. The foundation for integrated resource planning is the criteria used for
developing demand forecasts. For peak capacity planning, Avista transitioned from using
the coldest day on record to a 99t" percentile, or 1 out of 100 chances, methodology
applied to forecasted temperatures for each area within Avista's system; this is described
further in chapter 3. Avista plans to serve the expected peak day demand in each region
by maintaining firm pipeline transportation rights along with purchasing natural gas from
the market. Firm energy resources include natural gas, and distributed renewable
supplies, firm pipeline transportation, and storage resources. In addition to peak
requirements, Avista plans for demand occurring in non-peak periods such as winter,
shoulder months (April and October) and summer. The modeling process includes
optimization for every day of the 20-year planning period.
Avista does not make firm commitments to serve interruptible customers and therefore
assumes these loads would be curtailed on a peak day to serve firm customers. However,
these customers are considered in this IRP for compliance with the CPP and CCA.
Transport customers have their own interstate pipeline contracts to flow natural gas to
Avista's city gates and are not considered in peak day planning, unless necessary for
greenhouse gas program compliance purposes. A weather planning standard, blended
price curve of three studies developed by industry experts and an academically backed
customer forecast all work together to develop stringent planning criteria to test resource
needs.
The forecasted level of demand represents the amount of energy needed to be delivered;
however, on both an annual and peak-day basis, an additional 1% to 3% is needed to
account for additional natural gas used primarily for pipeline compressor station fuel to
Avista Corp 2025 Natural Gas IRP 31

Chapter 2: Preferred Resource Strategy
move the gas from different areas of demand on each interstate pipeline. The range of
1% to 3%, known as fuel, varies by delivery route and can change monthly depending on
the specific pipeline and tariff. This fuel is used to move the natural gas from point A on
the pipeline to point B or the delivery point. The FERC and National Energy Board
approved tariffs govern the percentage of required additional fuel supply.
Other fuels like RNG may or may not require this additional fuel as it is location
dependent. If a renewable fuel is within Avista's distribution system, the current design
does not include any compressors needed to move the gas and is pressure driven
( 'hapter 10).
CROME Planning Model
CROME is an internally developed mixed integer programming model used to solve
natural gas supply and transportation optimization questions. Mixed integer programming
is a proven technique to solve minimization/maximization problems. CROME analyzes
the complete problem at one time within the study horizon, while accounting for physical
limitations, carbon equivalent emissions, and contractual constraints. The software
analyzes thousands of variables and evaluates possible solutions to generate a least-
cost solution satisfying a given set of constraints. CROME considers the following
variables:
• Demand data, such as customer count forecasts and energy intensity by customer
type (e.g., residential, commercial, industrial, and transport).
• Weather data, including minimum, maximum, and average temperatures.
• Existing and potential transportation data describes the network for physical
movement of natural gas and associated pipeline costs.
• Existing and potential supply options include supply basins, revenue requirements
as the key cost metric for all asset additions and prices.
• Natural gas storage options with injection/withdrawal rates, capacities, and costs.
• Energy Efficiency potential.
• Daily energy demand by location and customer type (e.g., residential, commercial,
industrial, and transport)
Figures 2.1 through 2.3 are CROME network diagrams of Avista's demand centers and
resources (including supply resource options) for Idaho, Washington and Oregon. These
diagrams illustrate current and potential transportation and storage assets, flow paths and
constraint points.
Avista Corp 2025 Natural Gas IRP 32

.• '• Resource Strategy
•ure 2.1: CROME Idaho System Map
DSM ropane Storage'
Demand Response
Hydrogen
RNG
Synthetic Methane
Station 2 Basin ABC AECO Basin
Sumas Basin Sumas WAID Basin Kingsgate
LNG Stora
JP Out BC Pool Idaho SW W P
Stanfield Stanfeld
JP Storage JP Pool (NWP) (GTN) Stanfield Basin
Rockies Basin
•ure 2.2: CROME Washington •
DSM
Demand Response Propane Storage
Hydrogen Electrification
RNG
Synthetic Methane
Station 2 Basin ABC AECO Basin
Sumas Basin Sumas WAIDBasin Kingsgate
LNG Storage
JP Out BCPooI Washington SWWP
Stanfield Stanfield
JP Pool (NWP) (GTN) Stanfield Basin
Rockies Basin
- - - - - - - -- -
Avista Corp 2025

Chapter 2: Preferred Resource Strategy
Figure 2.3: CROME Oregon System Map
Stanfield Basin
JP Out
►
►
►
►
' Medford Poolmin
PFP
Hydrogen DSM
IL RNG Demand Response
Synthetic ification
The CROME model provides a flexible tool to analyze scenarios such as:
• Pipeline capacity needs and capacity releases;
• Effects of different weather patterns upon demand;
• Effects of natural and renewable gas price increases upon total gas costs;
• Emission constraints by planning zone;
• Storage optimization studies;
• Resource mix analysis for conservation;
• Weather pattern testing and analysis;
• Transportation cost analysis;
• Avoided cost calculations; and
• Short-term planning comparisons.
CROME also includes stochastic modeling and Monte Carlo capabilities to facilitate price
and demand uncertainty modeling and detailed portfolio optimization techniques to
produce probability distributions.
Avista Corp 2025 Natural Gas IRP 34

Chapter 2: Preferred Resource Strategy
Resource Integration
The following sections summarize the comprehensive analysis bringing demand
forecasting and existing and potential supply and demand-side resources together to form
the 20-year, least-cost plan.
Avista forecasts 11 service areas with distinct weather and demand patterns for each
area and pipeline infrastructure dynamics. The areas are Washington and Idaho (each
state is disaggregated into three sub-areas because of pipeline flow limitations and the
ability to physically deliver natural gas to an area); Medford (disaggregated into two sub-
areas because of pipeline flow limitations); and Roseburg, Klamath Falls, and La Grande.
In addition to area distinction, Avista also models demand by customer class and by end
use within each service area. The relevant firm customer classes are residential,
commercial, and industrial.
Customer demand is highly weather-sensitive. Avista's customer demand is not only
extremely seasonal but also highly variable. Figure 2.4 captures this historic variability
showing firm customer monthly system-wide average demand, minimum demand, and
maximum demand.
Figure 2.4: Total System Average Daily Load (Average, Minimum and Maximum)
400,000
— Average Load
350,000 Min Load
300,000 Max Load
250,000
200,000
o �
150,000
100,000
50,000 OEM 000` OSW /
0
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct
Avista Corp 2025 Natural Gas IRP 35

Chapter 2: Preferred Resource Strategy
Carbon Policy Resource Utilization Summary
Avista uses an estimated greenhouse gas (GHG) pricing as an incremental adder to
address state climate policies. GHG price adders increase the price of a dekatherm of
natural gas and impact resource selections and are summarized in Figure 2.5. In
Washington, the Climate Commitment Act (CCA) requires the use of allowances issued
by the Department of Ecology to be added to all consumption of natural gas consumed
within the state above the cap with prices starting at $44 per metric ton in 2026 and
moving to $117 per metric ton by 2045. Each CCA credit provides for one metric ton of
CO2e GHG emissions. CCA credits are received as an allotment to the utility, purchased
in the quarterly state auctions, or bought in the open market. A limited percentage of GHG
emissions reductions can also be from carbon offsets. Additionally, Washington's energy
efficiency cost effective selection analysis considers the social cost of greenhouse gas
(SCGHG), determined by the Interagency Working Group on Social Cost of Greenhouse
Gas using the 2.5% discount rate for future costs as required by RCW 80.28.395. For the
State of Oregon, Avista considers a proxy value of a community climate investment (CCI)
for meeting the Climate Protection Plan (CPP). As discussed in Chapter 7, this value is
only an estimate as the quantity of available CCIs is fixed, and other resources are
required to meet annual climate emissions requirements. Compliance to the CCA) and
CPP occur through instruments in each program, with the attributed costs of compliance
valued against supply side resources.
Figure 2.5: Carbon Legislation Sensitivities
$300
—CCA Allowance —CCI —SCC @ 2.5%
$250
N $200
$150
CD
$100
$50
$-
W r- 00 M O N M V LO W f` 00 M O N M V M
N N N N M M M M M M M M M M V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 36

Chapter 2: Preferred Resource Strategy
Transportation and Storage
Valuing natural gas supplies is a critical first step in resource integration. Equally
important is capturing all of the costs necessary to deliver the natural gas to customers.
Daily capacity of existing transportation resources (described in Chapter 5) is represented
by the firm resource duration curves depicted in Figure 2.6. These volumes drop as
seasonal contracts are in place with GTN as discussed in Chapter 5. The gas year begins
on November 1, when all available transportation contracts begin allowing for higher
volumes throughout the winter heating season.
Current rates for capacity are also available in Appendix 5. Forecasting future pipeline
rates can be challenging because of the need to estimate both the amount and timing of
rate changes. Avista's estimates and timing of future pipeline rate increases are based
on knowledge obtained from industry discussions and participation in pipeline rate cases.
This IRP assumes pipelines will file to recover costs at rates equal to inflation.
Figure 2.6: Existing Firm Transportation Resources
350
WA/ID Oregon
300
250
200
0
150
100
50
0
T_ T_ T_ T_ T_ T_ T_ T_
M W M N U') co T_ � r` O M to
T_ T_ T_ N N N M M M
Day of Gas Year
Demand and Deliverability Balance
After incorporating the system data into the CROME model, Avista generated an
assessment of demand compared to existing deliverability resource sources (Transport
Right) for several scenarios. Any underutilized resources will be optimized to mitigate the
costs incurred by customers until the resource is required to meet demand. This
management, of both long- and short-term resources, ensures the goal to meeting firm
customer demand in a reliable and cost-effective manner as described in �i idPLUI 0.
Avista Corp 2025 Natural Gas IRP 37

Chapter 2: Preferred Resource Strategy
Average Case demand, represented by the black line in Figures 2.7 and 2.8, is compared
to existing storage and transport rights on a peak day. This demand is net of energy
efficiency savings and shows the adequacy of Avista's transport rights under normal
weather conditions. For this case, current transportation resources exceed demand
needs over the planning horizon. Considerations to the importance of average demand
are discussed above when optimizing resources and releasing capacity to mitigate costs
along with contract type and terms for delivering natural gas in times of need. These
resources vary in ownership by state and by area and must match or exceed the volume
of expected demand.
Figure 2.7: Average Demand - Storage & Transport Rights for Feb,-----y 28Ih
600,000 ■GTN gackhaul
D-WA) GTN (OR - Wd Lateral)
GTN (OR) NWP (ID-WA)
500,000 siNWP ( )OR) ■JP Uteral
-WA)
■JP O ■KF
400,000
0 300,000
200,000 i
F
100,000
to r` O O O N M Iq LO to r~ O M O N M Iq LO
N N N N M M M M M M M M M M M 'Rt Mt 11 '41
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
Avista Corp 2025 Natural Gas IRP 38

Chapter 2: Preferred Resource Strategy
Figure 2.8: Average Demand - Storage & Transport Rights for December 20th
600,000 r GTN aackhaul
D-WA) R GTN (OR - Wd Lateral)
GTN (OR) NWP (ID-WA)
500,000 NWP (OR) ■JP ID-WA)
■JP (OR) ■ KF Lateral
400,000
0 300,000
200,000
100,000
Co r` CD M O N M Iq LO (.0 r` M M O N M I Lr)
N N N N M M M M M M M M M M IRt Iq Nt Iq IqIRt
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
Figure 2.9 shows system peak day demand compared to existing resources when Idaho,
Washington and La Grande experience peak days. In Figure 2.10, the Klamath Falls,
Medford and Roseburg planning regions all experience peak days; the loads for these
areas account for much less demand in comparison, including peak days. Peak day
demand is also net of energy efficiency savings. Avista is still long on transport rights,
consistent with prior IRP expectations. Peak day criteria is important as it protects our
customers and their structures during extreme weather. Avista will evaluate future
capacity releases or allocation between states as demand projections materialize.
Currently, Avista is not proposing any change to its transportation rights.
Avista Corp 2025 Natural Gas IRP 39

Chapter 2: Preferred Resource Strategy
Figure 2.9: Peak Day Demand - Storage & Transport Rights for February 28tn
600,000 �GTN (ID-WA) PF GTN (OR - Wd Lateral)
GTN Backhaul (OR) NWP (ID-WA)
500,000 ■NWP (OR) ■JP (I D-WA)
■JP (OR) ■ KF Lateral
400,000
0 300,000
200,000
1, I
100,000
CD f` M M O � N M � if) Cfl f` M M O N M "CT tr)
N N N N M M M M M M M M M M IR* Iq � � IR* Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 2.10: Peak Day Demand - Storage & Transport Rights for December 20th
600,000 GTN (ID-WA) ■GTN (OR - Wd Lateral)
GTN Backhaul (OR) NWP (ID-WA)
500,000 NWP (OR) ■JP (ID-WA)
■JP (OR) ■KF Lateral
400,000
0 300,000
200,000 F
-M r
100,000
CD I- 00 M O N M Ict In C0 f- 00 M O N M qCT U1
N N N N M M M M M M M M CO M q 'rt 11* qct qI
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
Avista Corp 2025 Natural Gas IRP 40

Chapter 2: Preferred Resource Strategy
Avista's interstate pipeline transportation position is strong compared to existing peak
demand; the IRP must also consider meeting emissions reductions for future demand
changes. New capacity resources, such as on-system storage for resiliency in the event
short term energy supplies are interrupted due to transportation outages, is a viable
resource addition that Avista will further study. This Resiliency scenario is described in
detail in Chapter 8 and will be an action item of this IRP to determine if Avista should
pursue additional natural gas storage.
State Environmental Compliance
When considering emissions compliance under the CCA and CPP, Avista requires
additional resources or compliance instruments. GHG emissions compliance addresses
program constraints of the CCA and CPP, plus these regulations require planning for
transport customers where past plans did not. In both Figure 2.11 and Figure 2.12,
equivalent GHG emissions from all customer demand can be found in the line chart
compared to the areas of each chart indicating the quantity of compliance instruments
received from each program. The white area between these chart elements displays the
resource needs for program compliance and clearly shows noncompliance will occur if no
actions are taken to offset emissions or utilize other options per program rules, where the
total emissions exceed the annual limits. These shortages occur in 2026 in Washington
and continue through the end of the study in 2045. Oregon shortages begin in the second
compliance period (2028-2029). Further analysis is required to determine demand and
price in an unknown future and will be discussed and compared to other sensitivities and
scenarios, where appropriate, in Chapter 8.
Avista Corp 2025 Natural Gas IRP 41

Chapter 2: Preferred Resource Strategy
Figure 2.11: Washington Emissions Forecast Compared to No Cost Allowances
1 ,400,000
No Cost Allowances
1 ,200,000 ! WA Load
1 ,000,000
N 800,000
O
600,000
400,000
200,000
N M N* LO W r` 00 O O N M q* LO
N N N N M M M M M M M M M "qtKt
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 2.12: Oregon Emissions Forecast Compared to CPP Cap
700,000
Pr CPP Cap
600,000 OR Load
a)
5001000
N
0 400,000
300,000
2001000
100,000
CD ti 00 M O N Mq,* LO W r~ CO M O � N M "I UI)
N N N N M M M M M M M M M M � "qt 10 Mt 11 'q*
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 42

Chapter 2: Preferred Resource Strategy
New Resource Options and Considerations
All scenarios analyzed in this IRP process consider resource needs based on the climate
policies in Oregon and Washington. These options have been input into the CROME
model to help solve the energy demand and emissions reduction requirements. Table 2.1
highlights supply-side and demand-side resource options as discussed in later chapters.
i ame 2.1: New supply-Side and Demand-Side Kesource Options
Supply-Side Resource Options Demand-Side Resource Options
Natural Gas + Compliance Instrument in Demand Response by program
OR (CCI) and WA (allowance or offset)
Blue, Green and Pyrolysis Hydrogen Space Heat, Water Heat, Other-
Electrification
RNG by source (Dairy, Landfill, Food Carbon Capture, Utilization and Storage
Waste, and Wastewater) (CCUS)
Biomass and Electrolysis - Synthetic Energy Efficiency (CPA from AEG and ETO)
Methane
Renewable Thermal Credits (RTC) by Natural Gas
source as described in RNG
Resource cost is the primary consideration when evaluating resource options, although
other factors mentioned below also influence resource decisions. Newly constructed
resources are typically more expensive than existing resources, but existing resources
are in exceedingly short supply. Newly constructed resources provided by a third party,
such as a pipeline, may require significant contractual commitment. However, newly
constructed resources are often less expensive per unit if a larger facility is constructed
because of economies of scale. Resource cost estimates are in Chapter 6. A full set of
resource options is provided in Table 2.2 to show when resources are available to select
in the CROME model and if there are any limitations.
Table 2.2: New Resources Availability
Resource Type Volumetric Restriction First Year of
Availability
Allowances 10% of Market per program rules (CCA) 2026
Community Climate 15% (2025-2027), 20% 2028+ (CPP) 2026
Investments
Demand Response CPA from AEG for potential 2026
Electrification No constraints, up to total energy demanded on 2026
LDC by area/class/year
Energy Efficiency CPA from AEG and ETO 2026
Renewable Thermal NW Technical Potential (ICF) 2026
Credit
Avista Corp 2025 Natural Gas IRP 43

Chapter 2: Preferred Resource Strategy
Propane Storage 30,000 Dth 2028
Hydrogen NW Technical Potential to Avista (ICF) & 20% 2030
by volume
Synthetic Methane NW Technical Potential to Avista (ICF) 2030
Renewable Natural NW Technical Potential (ICF)for allocation of 2030
Gas 1.5MM Dth Total Availability
Liquified Natural Gas 1 Bcf Total & 0.1 Bcf Daily W/D 2030
Carbon Capture, Constraints to Avista high volume customers 2030
Utilization and Storage (ICF)
Lead Time Requirements
New resource options can take up to five or more years to put in service, with the
exception being the propane storage option of two years. Open season processes to
determine interest in proposed pipelines, planning and permitting, environmental review,
design, construction, and testing contribute to longer lead time requirements for new
facilities. Recalls of released pipeline capacity typically require advance notice of up to
one year. Even energy efficiency programs can require significant amounts of time from
program development and rollout to the realization of natural gas savings.
Peak Versus Base Load
Avista's planning efforts include the ability to serve firm natural gas loads on a peak day,
as well as all other demand periods. Avista's core loads are considerably higher in the
winter than in the summer. Due to the winter-peaking nature of Avista's demand,
resources that cost-effectively serve the winter load without an associated summer
commitment may be preferable. Alternatively, it is possible that the costs of a winter-only
resource may exceed the cost of annual resources after capacity release or optimization
opportunities are considered.
Resource Usefulness
Available resources must effectively deliver supply to the intended region. Given Avista's
dispersed service territories, it is often impossible to deliver resources from a resource
option, such as storage, without acquiring additional pipeline transportation. Pairing
resources with transportation increases cost. Other key factors that can contribute to the
usefulness of a resource are viability, capacity, and reliability along with carbon intensity.
If the potential resource is either not available currently (e.g., new technology) or not
reliable on a peak day (e.g., non-firm), they may not be considered as an option for
meeting unserved demand.
"Lumpiness" of Resource Options
Newly constructed resource options are often only available in "lumpy" sizes. This means
the new resources may only be available in larger-than-needed quantities and only
available every few years. This lumpiness of resources is driven by the cost dynamics of
Avista Corp 2025 Natural Gas IRP 44

Chapter 2: Preferred Resource Strategy
new construction, where lower per unit costs are available with larger expansions and the
economics of the expansion of existing pipelines, or the construction of new resources
dictate additions infrequently. The lumpiness of new resources provides a cushion for
future growth. Economies of scale for pipeline construction provide the opportunity to
secure resources to serve future demand increases. Part of this problem can be met by
contracting out the excess resources until needed to serve load growth.
Competition
LDCs, end-users and marketers compete for regional resources. The Northwest has
efficiently utilized existing resources and has an appropriately sized system. Currently,
the region can accommodate the regional energy demand needs. However, future needs
are expected to vary, and regional LDCs may find they are competing with other parties
to secure the same firm resources for their customers. RNG resources specifically will
have an increased amount of competition as the drive for carbon-reducing supplies
increases with associated policies in different states.
Risks and Uncertainties
Investigation, identification, and assessment of risks and uncertainties are critical
considerations when evaluating supply resource options. For example, resource costs
are subject to degrees of estimation, partly influenced by the expected timeframe of the
resource need and rigor determining estimates, or estimation difficulties because of the
uniqueness of a resource. Lead times can have varying degrees of certainty ranging from
securing currently available transport (high certainty) to building underground storage
(low certainty).
Energy Efficiency Resources
Integration by Price
As described in Chapter 4, Avista determines energy efficiency cost effectiveness without
future energy efficiency programs in the load forecast. This preliminary study provides an
avoided cost curve for use by both Applied Energy Group (AEG) and the Energy Trust of
Oregon (ETO) to evaluate the cost effectiveness of energy efficiency programs against
the initial avoided cost curve using the Utility Cost Test and Total Resource Cost Test.
The therm savings and associated program costs are incorporated into the CROME
model thereby reducing the load forecast.
Energy Efficiency Selection
Using the avoided cost thresholds, AEG selected all potential cost-effective energy
efficiency programs for the Idaho and Washington service areas, while ETO performed
the CPA study for Oregon excluding transport and residential low income which were also
completed by AEG. Figure 2.13 shows the potential energy efficiency savings in
dekatherms for each jurisdiction from the resource potential for the PRS. The total
cumulative energy savings by 2045 could offset over 4 million dekatherms.
Avista Corp 2025 Natural Gas IRP 45

Chapter 2: Preferred Resource Strategy
Figure 2.13: Cumulative Demand Served by Energy Efficiency
5
■WA ■ID ■OR WA Tprt OR Tprt
C 4 .
c
0
c 3
as
c
•� 2 -
M
N
s
0
Cp r` M M O N M 'R* LO W f` M M O N MR* Lo
N N N N M M M M M M M M M M IR* Iq "I Iq "IIR*
O M O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Preferred Resource Strategy (PRS)
The PRS considers current supply-side resources and new resource options to solve the
energy and environmental policy program objectives. The resources Avista models for in
the IRP include five types of RNG, four types of hydrogen, two types of synthetic methane,
and industrial and direct carbon capture. Each of these resources and their associated
costs are discussed in Chapter 6. The alternative fuel sources vary by the size of resource
and cost estimates based on the facility type. Electrification of major end uses is also
included for Oregon and Washington based on environmental policy and GHG reduction
goals as an option and is included by planning region for space heat, water heating and
cooking as detailed in r'hantPr*1. All options discussed above are treated so if any amount
is taken, future years must also take this same amount and cost of the year selected as
a minimum. Demand Response is treated in a similar fashion as if a program is selected,
program costs and demand savings must be used going forward. Renewable thermal
credits (RTC), allowances, community climate investments, and natural gas are all
variable from year-to-year except for natural gas or physical alternative fuels as they can
be carried from season to season by injecting into storage. Propane and LNG storage are
also considered as if it is selected it carries forward across the forecast horizon.
To solve unserved demand and emissions goals, a set of resource options are available
to meet the requirements of energy, capacity and emissions constraints. ',.,iiauLei o
includes summaries of weather and demand. Prices and volumes of resources will vary
as shown historically, as planning for new resources must be considered on a stochastic
Avista Corp 2025 Natural Gas IRP 46

Chapter 2: Preferred Resource Strategy
basis. A final PRS will be chosen based on all modeling results and comparisons and
may change from the selections discussed in this chapter.
Idaho PRS
The Idaho PRS continues to utilize natural gas as the least cost resource alternative from
Avista's currently available supply basins and storage. In addition to maintaining natural
gas as the least cost fuel, new energy efficiency programs are selected to reduce energy
demand as shown in Figure 2.14. Energy efficiency lowers demand by over 4% by 2045.
Natural gas will be acquired for Idaho on a least cost basis from the available hubs as
illustrated in Figure 2.15. This figure displays a combination of purchases from the
connected hubs available with the primary choice coming from the AECO basin. This
basin is geographically closest to Avista's Idaho territory and is where the Company's
largest pipeline capacity is located. Recent changes regarding tariffs on Canadian
sourced natural gas started occurring after the completion of the modeling for the 2025
IRP. The timing and size of the potential new tariffs is still in development. However, the
cost differential for AECO natural gas should remain the lowest cost supply basin. Tariffs
will be analyzed more thoroughly in the 2027 IRP when more details are known.
Figure 2.14: Idaho Preferred Resource Strategy
12 ■ Natural Gas Energy Efficiency
10
0 8
v
6
E
L
4
Y
CD r` O O O � N M 10 LO (.0 r` O O O T- N M Mt LO
N N N N M M M M M M M M M M Iq Iq � I
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 47

Chapter 2: Preferred Resource Strategy
Figure 2.15: Idaho Natural Gas Basin Supply
14
AECO Basin Rockies Basin Stanfield Basin
12 Station 2 Basin Sumas Basin WAID Basin
0 10
E 6
a�
4
Y
2
CD r` W M O N M I LO CD r` M M M N M qq Ln
N N N N M M M M M M M M M ('M qq Iq M* ql* Iq Iq
O M O O O O O O O O O O O M O O O O O O
N N N N N N N N N N N N N N N N N N N N
Oregon PR.(
Oregon's PRS has changed as compared to previous plans. Changes adhere to the new
environmental goals of the 2024 CPP and the estimated energy demand. In the near-
term, the new resource need is met via a combination of RNG from Landfill Gas (LFG),
Wastewater Treatment Plants (WWTP), energy efficiency, Community Climate
Investments (CCls), RTCs procured to date, carbon capture, and conventional natural
gas. RNG is added to the resource mix beginning in the 2030s, as illustrated in Figure
2.16. By 2045, customer demand will be met by 12.8% energy efficiency and 26% RNG.
The remaining demand will utilize natural gas from the basins shown in Figure 2.17 and
indicates a declining utilization of natural gas over the forecast horizon. In each figure,
the dark blue area at the bottom of the chart depicts natural gas with no emissions
instrument for compliance.
Avista Corp 2025 Natural Gas IRP 48

Chapter 2: Preferred Resource Strategy
Figure 2.16: Oregon Preferred Resource Strategy — Firm Customers
■ Natural Gas CCI
10 Currently Contracted RTCs Carbon Capture
■ RNG Energy Efficiency
c 8
0
6
E
L
CD
Y 4
a�
� 2
CG r` CO M O r N MIq* LO CO ti co QM O N MIle LO
N N N N M M M M M M M M M M ' 'q 'q 'q 'q
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 2.17: Oregon Natural Gas Basin Supply — Firm Customers
10 ■ AECO Basin Malin Basin Rockies Basin
Stanfield Basin Sumas Basin
c 8
0
U) 6
� 4
Y
m
2
CO r` O O O N M Nt L0 (D r` O M O N M Nt L0
N N N N M M M M M M M M M M qI 'q qO qO qI 'R*
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 49

Chapter 2: Preferred Resource Strategy
The number of CCIs available to Avista declines with the cap each year. Also, due to the
rising costs of CCIs, alternative resources become cost effective in comparison. This
leads to additional resources being brought onto the system on an annual basis through
the end of the study timeframe, as depicted in Table 2.3.
Table 2.3: Average Daily Resource Quantities by Year
CarbonNatural RNG EE
Gas Capture Contracted
OIL-- --1- -Ak- A- RTCs
2026 24,170 0 133 0 0 0
2027 23,970 0 288 0 0 0
2028 23,664 0 454 0 238 417
2029 23,410 0 618 0 236 412
2030 20,992 2,133 806 0 0 0
2031 19,846 2,947 1,002 0 0 0
2032 18,097 4,373 1,203 0 0 0
2033 17,296 4,901 1,417 0 0 0
2034 15,855 6,043 1,633 0 1,216 201
2035 15,483 6,220 1,855 0 1,187 197
2036 15,340 6,118 2,075 2,206 0 370
2037 14,678 6,511 2,308 2,111 0 354
2038 14,827 6,034 2,539 3,973 0 145
2039 14,306 6,185 2,773 3,833 0 140
2040 13,594 6,566 3,002 3,751 0 142
2041 12,907 7,000 3,253 3,561 0 135
2042 11,995 7,558 3,502 4,309 0 148
2043 12,122 7,123 3,755 4,355 0 150
2044 10,804 8,124 4,002 4,452 0 0
2045 10,129 8,545 4,241 4,174 0 0
Also, due to the divergent weather locations, the risk of the amount of needed CCIs is
volatile. The coldest weather is found in La Grande and Klamath Falls where peak days
have been observed in the past 30 years. In contrast, Medford and Roseburg have
warmer climates and do not get extreme temperatures. Figure 2.18 illustrates the quantity
of CCIs required in the PRS. Compliance instruments of the CPP are expected to cover
Avista's emissions for the first compliance period (2025-2027). Beginning in the second
compliance period (2028-2029) CCIs are chosen to help bridge the gap to when the model
is offered alternative fuels like RNG. Additional CCIs are selected from 2032 to 2035 until
enough RNG, load reduction and carbon capture are in place to meet emissions goals
through the planning horizon.
Avista Corp 2025 Natural Gas IRP 50

Chapter 2: Preferred Resource Strategy
Figure 2.18: Community Climate Investment Quantity — All Customers (MTCO2e)
40,000
35,000
30,000
v_) 25,000
U
U 20,000
0
15,000
10,000
5,000
W r- CO On O N M LO W I` 00 On O r N M q1 LO
N N N N M M M M M M M M M M q1 � � � � 11qr
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Washington PRF
Washington's PRS is like previous IRP results except for lower projected demand. The
PRS shown in Figure 2.19 shows conventional natural gas and energy efficiency as the
primary energy source options until the end of the study horizon (2045). Energy efficiency
reduces demand by 11% while small portions of RNG are utilized to cover energy and
emissions reductions when cost competitive against CCA pricing. Natural gas will
continue to be procured from the least cost supply basin for Washington as shown in
Figure 2.20.
The specific resource selection by year is shown in Table 2.4. Avista does not expect a
significant reduction in traditional natural gas utilization as the primary fuel in Washington
with the CCA allowance prices assumed in this expected case. identifies how
a reduction in traditional natural gas use may occur by way of higher reliability, higher
costs of supply, higher cost of allowances, or lower alternative volumes available.
Avista Corp 2025 Natural Gas IRP 51

Chapter 2: Preferred Resource Strategy
Figure 2.19: Washington Preferred Resource Strategy — Firm Customers
25 ■Allowances (Free) Allowances (Given)
Allowances (Purchased) Currently Contracted RTCs
N 20 RNG Energy Efficiency
c
0
15
10
�a
Y
0 5
CO f� 00 M O N M LO CO I` M M M N M Iq LO
N N N N M M M M M M M M M ('M Iq Iq M* M* IqIRt
O M O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 2.20: Natural Gas Basin Supply —Washington — Firm Customers
25
■ AECO Basin Rockies Basin Stanfield Basin
Station 2 Basin Sumas Basin WAID Basin
20 -
c
0
15
E
0 10 ■
ca
Y
a�
0 5
W I` CO M O N MR* LO W r- 00 M O r N M qI W)
N N N N M M M M M M M M M M q � ICT qI qI
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 52

Chapter 2: Preferred Resource Strategy
Table 2.4: Average Daily Resource Quantities by Year- Washington
Natural RNG EE Allowances Allowances Allowanc Currently
Gas (Free) (Given) Purchase Contracted RTCs
2026 55,635 0 197 7,172 28,687 22,165 391
2027 54,967 0 425 4,856 27,517 22,989 86
2028 53,812 0 687 2,881 25,927 25,441 96
2029 52,645 0 936 1,270 24,130 27,720 104
2030 51,397 0 1,228 0 21,914 29,997 113
2031 49,969 0 1,539 0 21,017 29,398 0
2032 48,656 0 1,862 0 20,066 29,031 0
2033 47,493 0 2,189 0 19,224 28,705 0
2034 46,329 0 2,511 0 18,328 28,433 0
2035 45,364 0 2,819 0 17,431 28,391 0
2036 44,271 0 3,096 0 16,490 28,238 0
2037 43,226 0 3,339 0 15,639 28,041 0
2038 41,891 283 3,552 0 14,742 27,595 0
2039 40,232 795 3,732 0 13,846 26,814 0
2040 40,010 0 3,892 0 12,914 27,535 0
2041 39,263 0 4,037 0 12,053 27,651 0
2042 38,273 0 4,143 0 11,156 27,556 0
2043 37,582 0 4,247 0 9,861 28,147 0
2044 36,797 0 4,321 0 8,543 28,689 0
2045 36,227 0 4,387 0 7,271 29,401 0
Allowances and offsets for this plan are considered interchangeably and are compared
to one another with available options at the time of purchase. If Avista can obtain offsets
at a lower price than allowances, offsets will be purchased. The PRS selects program
instruments each year as shown in Figure 2.21. The delta between the "Given" line and
"No Cost" bar is the free CCA allowances Avista can use directly for compliance purposes.
Avista Corp 2025 Natural Gas IRP 53

Chapter 2: Preferred Resource Strategy
Figure 2.21: CCA Allowances/Offsets Quantities by Type (MTCO2e)
1 ,400,000
m No Cost Purchased — Given
1 ,200,000
a 1 ,000,000
U
� 800,000
O IQ 600,000
O
400,000
200,000
CO r` M M M T- N MI�r LO CO r` M M M N MIRT LO
N N N N MMMMMMMMM M Iq Iq MT � IRT Iq
O O O O M O O O O M O O O O M O O O O O
NNNNNNNNNNNNNNNNNNNN
Transport Customer State Environmental Compliance
Figure 2.22 shows the PRS for Washington transport customers where allowances are
broken out by the percentage of load for their share of the "Free" and "Given" CCA
allowances. Demand side management, or energy efficiency, portion is from the
achievable economic potential analysis (TRC) Conservation Potential Assessment
provided by AEG. Figure 2.23 shows the same breakout for Oregon transport customers
with a share of Oregon resources for carbon capture and RNG, including the amount of
CCls in dekatherm equivalency.
A paradigm shift occurs with the current methods and tariff structure of transport
customers as they currently provide their own fuel and resources to deliver their supply
to Avista city gates. These charts do not predict which entities will purchase the alternative
fuels, but rather that it may be the least cost solution to meet the climate goals given
model inputs.
Avista Corp 2025 Natural Gas IRP 54

Chapter 2: Preferred Resource Strategy
Figure 2.22: Washington Preferred Resource Strategy —Transport Customers
4.0 ■Allowances(Free) ■Allowances (Given)
3.5 'Allowances(Purchased) Currently Contracted RTCs
■RNG ■DSM
c 3.0
g 2.5
2.0
1.5
0 1.0
0.5
0.0
CO I� O C9 O (IN M Iq If) W I� co 09 O N M Iq UA
N N N N M M M M M M M M M M V V V V V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 2.23: Oregon Preferred Resource Strategy - Transport Customers
■ Natural Gas ■ CCI
3.0 Currently Contracted RTCs Carbon Capture
■ RNG Energy Efficiency
o 2.5 ■ —
2.0
1.5
L
1.0
0
0.5
0.0
W I- co M O N M Iq LO W I� co M O N M Iq LO
N N N N M M M M M M M M M M V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 2: Preferred Resource Strategy
All Customer Summary
Figures 2.24 to 2.25 show Washington and Oregon's PRS considering all customer
classes and resources selected. Quantities selected are spread around compliance
period and may differ slightly from modeled selection. Figure 2.26 is a summary
illustration for the system including all areas and classes modeled for information
discussed above.
Figure 2.24: Washington Preferred Resource Strategy —All Customers
30 m Allowances (Free) - Allowances (Given)
Allowances (Purchased) Currently Contracted RTCs
U1
25 RNG Energy Efficiency
C
0
20
E 15
L
L
a 10
Y
5 MORI
CD I` 00 O O N M IqU") c.D I` 00 O O N M Iq LO
N N N N CO CO CO CO M CO CO CO CO M 1 11 NTlc* 10
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 2: Preferred Resource Strategy
Figure 2.25: Oregon Preferred Resource Strategy -All Customers
14 ■ Natural Gas ■CCI
Currently Contracted RTCs Carbon Capture
12 ■ RNG Energy Efficiency
10
8
L
6
M
4
CID
0
2
M O N M V U1 W ti O M O N M V U1
N N N N M M M M M M M M M M V V V V V V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 2.26: System Preferred Resource Strategy -All Customers
■Natural Gas ■Allowances (Free)
60 ■Allowances (Given) Allowances (Purchased)
■CCI Currently Contracted RTCs
50 Carbon Capture ■ RNG
c Energy Efficiency
30
CID
L
Y 20
aD
0
10
W I` W M O N M V Ln W I` W M O N M V In
N N N N M M M M M M M M M M
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 57

Chapter 2: Preferred Resource Strategy
Avista's Aspirational Clean Energy Goals'
In 2021, Avista announced an aspirational goal to be carbon neutral by 2045. Natural gas
has played a key role in reducing greenhouse gas emissions in the United States as
electrical power plants have converted from coal to cleaner burning natural gas. In
addition, the direct use of natural gas by customers in their homes is a more efficient use
of natural gas as compared to its use for generating electricity to meet the same need.
And when compared to burning wood, heating oil and other combustible fuel sources,
natural gas emits fewer air pollutants. While natural gas may be a cleaner fuel than some
other sources, we recognize there is an opportunity to further improve and lower our
natural gas emissions going forward. We have developed a strategy for carbon reduction
from our natural gas operations and have identified several pathways to get us there. The
three primary pathways included in our strategy are:
• Diversify and transition from conventional fossil fuel natural gas to renewable
natural gas (RNG), hydrogen, and other renewable biofuels.
• Reduce consumption via conservation, energy efficiency, and new technologies.
Purchase carbon offsets as necessary. Avista remains committed to meeting the
needs for reliable and affordable energy while advancing environmental
stewardship, and our actions demonstrate these values.
To help achieve our aspirational goal and to reduce our carbon emissions from our natural
gas operations, we have been actively pursuing renewable natural gas (RNG) projects in
alignment with our strategies. Avista has recently entered into long-term purchase
agreements to acquire the environmental attributes associated with the RNG from the
following regional and national projects on behalf of our customers:
• Horn Rapids Landfill (Richland, WA)—project producing 1.6 million annual therms
of RNG.
• Blackhawk Landfill (Waterloo, IA)—project producing 2.6 million annual therms of
RNG.
• Bayview Landfill (Elberta, UT)—project producing 2.5 million annual therms of
RNG.
• Quad Cities Landfill (Milan, IL)—project producing 3 million annual therms of RNG.
In all, Avista has contracted for the Renewable Thermal Certificates (RTCs) associated
with 9.7 million therms of produced RNG on an annual basis from these landfill projects,
which is equivalent to the annual amount of natural gas used by approximately 17,500 of
our customers.
' Corporate Responsibility Report
Avista Corp 2025 Natural Gas IRP 58

Chapter 2: Preferred Resource Strategy
Reaching our aspirational natural gas goal will require further improvements in costs,
technology, and reliability associated with renewable fuels and green hydrogen. If these
required improvements are not realized or not affordable in the future, we may not meet
our aspirational goal in the desired timeframe. Meeting our aspirational natural gas goal
may also require accommodation from regulatory agencies insofar as we may need to
acquire carbon offsets to meet our aspirational goal. The natural gas industry has served
a vital and essential role in delivering reliable and affordable energy to millions of
customers, businesses and industries throughout our country and the world. This industry
has evolved and will need to continue evolving to meet the real climate change challenges
confronting us all. We will continue to engage in collaborative, solutions-oriented
discussions with interested parties to highlight the importance of maintaining our natural
gas pipeline assets and fuels as a reliable, affordable consumer choice and as a valuable
resource for handling our region's peak energy demand. We anticipate natural gas will be
a vital part of our energy mix as we continue our transition to a lower carbon future, and
both our electric and natural gas IRPs demonstrate the role of natural gas in serving our
customers and communities into the future. When compared to the PRS, the adjustment
of resources necessary to meet this trended (2026-2045) carbon neutral goal can be
found in Figure 2.27.
Figure 2.27: PRS Changes to Meet Carbon Neutral Goal of 100% by 2045
20 ■ Natural Gas ■Alternative Fuels
°' Allowances (Purchased) ■ CCI
2. 15 RTC Carbon Capture
CD 10
0
5
0 0
-5
-10
CO I` 00 O O N M Iq Ln W I` W O O N M Ln
N N N N M M M M M M M M M M
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 59

Chapter 2: Preferred Resource Strategy
This Page is Intentionally Left Blank
Avista Corp 2025 Natural Gas IRP 60

Chapter 3: Demand Forecast
3. Demand Forecast
Section Highlights:
• Washington annual average load growth is -1.68%
• Idaho annual average load growth is +0.37%
• Oregon annual average load growth is -0.31%
• In contrast to previous IRP, Avista used end-use modeling techniques to develop
the long-term load forecast.
• Between warming temperature expectations, electric heat pump additions, and
energy efficiency, Avista expects a decrease in demand per customer, with minimal
customer additions in Oregon and Washington
The IRP development begins with a demand forecast. Understanding and analyzing key
demand drivers and their potential impact on forecasts is vital to the planning process.
Utilization of historical data provides a reliable baseline; however, forecasting will always
have uncertainties regardless of methodology and data integrity. This IRP mitigates the
uncertainty by considering a range of scenarios to evaluate and prepare for a broad
spectrum of potential outcomes.
Demand Areas
Avista defines eleven demand areas, structured around the pipeline's ability to serve them
within the CROME model (Table 3.1). These demand areas are aggregated into five
service territories and further summarized as North or South divisions for presentation
throughout this IRP.
Table 3.1: Geographic Demand Classifications
Washington NWP Spokane North
Washington GTN Spokane North
Washington Both Spokane North
Idaho NWP Coeur D'Alene North
Idaho GTN Coeur D'Alene North
Idaho Both Coeur D'Alene North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Roseburg South
Roseburg Medford/Roseburg South
Klamath Falls Klamath Falls South
La Grande La Grande South
Avista Corp 2025 Natural Gas IRP 61

Chapter 3: Demand Forecast
Customer Forecasts
Avista's customer load base includes firm residential, commercial, and industrial
categories. For each of the customer categories, Avista develops customer forecasts
incorporating national economic forecasts and regional economies. The key economic
drivers to forecast customer growth are U.S. Gross Domestic Product (GDP) growth,
national and regional employment growth, and regional population growth expectations.
Avista combines this data with local knowledge about sub-regional construction activity,
age and other demographic trends, and historical data to develop the 20-year customer
forecasts. Forecasted residential customers by state are shown in Figure 3.1. Customer
forecasts for commercial load are estimated based on historic customer counts divided
by the number of square feet as provided by the AEG forecast and shown in Figure 3.2.
To convert AEG's forecasted industrial customers, which use the number of employees
per facility, Avista applied the same estimate using historic industrial customers to imply
an estimated industrial customer count shown in Figure 3.3.
Figure 3.1: Residential Customer Forecast
180,000
L 160,000
a�
0 140,000
v) 120,000
U
100,000
80,000
v, 60,000
a�
40,000
0
20,000 ID OR WA
CD r~ co M O W N CO 11 LO CD r` CO QM O N M 11 LO
N N N N M M M M M M M M M M ' NT NT NT "I
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
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Chapter 3: Demand Forecast
Figure 3.2: Commercial Customer Forecast
16,000
14,000
0 12,000
v 10,000
8,000
L
Q�
E 6,000
v 4,000
° 2,000 ID OR WA
tD t~ CO M O N MIRt LO CD t` CO M O N M Iq LO
N N N N M M M M M M M M M M � ICT 11 qtICT
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N (N N
Figure 3.3: Industrial Customer Forecast
100
V)
90
a) 80
E
0 70
�j 60
-M 50
L
n 40
30
0 20
10 ID OR WA
CD r~ O O O N M19* LO CO t` M O O N M � U")
N N N N M M M M M M M M M M Iq Iq NrITT 10
O O O O O O O O O O O O O Co O O O O Co O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 63

Chapter 3: Demand Forecast
The customer forecast in the 2025 IRP assumes growth based on an end use forecast
developed by Applied Energy Group (AEG) using the same tool to provide conservation
potential assessments (CPA) named LoadMAPTM. This model is used to directly inform
the official load forecast, including effects of state energy codes, potential electrification,
and market trends. Other major modeling inputs and sources are illustrated in Figure 3.4.
Figure 3.4: LoadmapTM Inputs and Sources
vim
Avista foundational data Survey data showing Technical data on end- State and Federal Market trends and
presence of equipment use equipment costs energy codes and effects
and energy standards
consumption
Avista power sales by schedule Avista:Residential customer Region al Technical Forum Washington State Energy Code RTF market baseline data
Current and forecasted survey conducted in 2013 workbooks Idaho Energy Code Annual Energy Outlook
customer counts NEEA:Residential and Northwest Power and Federal energy standards by purchase trends(in baseyear)
Retail price forecasts by class Commercial Building Stock Conservation Council's 2021 equipment class
Assessments(RBSA 2016 and Power Plan workbooks
CBSA 2019) US Department of Energy and
US Energy Information ENERGYSTAR technical data
Administration:Residential, sheets
Commercial,and Energy Information
Manufacturing Energy Administration's Annual Energy
Consumption Surveys(RECS Outlook/National Energy
2020,CBECS 2018,and MECS Modeling System data files
2015)
The forecast process includes market characterization (segmentation, end use and
technology list) and are allocated between electric loads and gas loads by the expected
customer behavior of fuel choice. The baseline projection is then run on an annual basis
based upon the customer forecast, stock turnover, purchasing decisions for equipment,
and the weather forecast. The system total load forecast from the model includes a
combination of electrification, building codes, and naturally occurring energy efficiency
causing overall natural gas loads to decline by 7% across the forecast period. Washington
specifically has a much stronger downward trend in isolation but is offset by growth in
Idaho. A weather forecast by planning area is included in these projected load demands
and is discussed in detail later in this chapter. Results of this demand forecast excluding
Avista sponsored energy efficiency programs are shown by state and by end use in
Figures 3.5 to 3.8 (excludes transport customer loads).
Avista Corp 2025 Natural Gas IRP 64

Chapter 3: Demand Forecast
Figure 3.5: Idaho Demand by End Use
18
Ind-Space Heating Ind-Process
16 Ind-Miscellaneous Com-Water Heating
Com-Space Heating Com-Miscellaneous
14 Com-Food Preparation Res-Water Heating
Res-Space Heating Res-Secondary Heating
o '12 ■ Res-Miscellaneous ■ Res-Appliances
o 10
0
C 8
0
6
4
2
0
W f� CO OA C r N M qe in W f` 00 M C r N M qe tn
N N N N M M M M M M M M M M 'Re qe qeIle qe qe
C C C C C C C C C C C C C C C C C C C C
N N N N N N N N N N N N N N N N N N N N
Figure 3.6: Oregon Demand by End Use
14 Ind-Space Heating Ind-Process
Ind-Miscellaneous Com-Water Heating
12 Com-Space Heating Com-Miscellaneous
Com-Food Preparation Res-Water Heating
r 10 Res-Space Heating Res-Secondary Heating
o ■ Res-Miscellaneous Res-Appliances
4- 8
0
0
=0 6
4
2
0
CC I� oo O� C r N M Ile tn M r` CO OA C r N M qe W)
N N N N M M M M M M M M M M R* le v v V le
C C C C C C C C C C C C C C C C C C C C
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 65

Chapter 3: Demand Forecast
Figure 3.7: Washington Demand by End Use
32 Ind-Space Heating Ind-Process
28 Ind-Miscellaneous Com-Water Heating
Com-Space Heating Com-Miscellaneous
Com-Food Preparation Res-Water Heating
s 24 Res-Space Heating Res-Secondary Heating
0 20 ■ Res-Miscellaneous Res-Appliances
0
16
c
12
8
4
Q
M f` CO a) C r N M � W) C ti 00 M C r N M qe W)
N N N N M M M M M M M M M M Re Re Re Re qe qe
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
Figure 3.8: System Demand (Firm Customers)
60 Ind-Space Heating Ind-Process
Ind-Miscellaneous Com-Water Heating
50 Com-Space Heating Com-Miscellaneous
Com-Food Preparation Res-Water Heating
Res-Space Heating Res-Secondary Heating
0 40 ■ Res-Miscellaneous ■ Res-Appliances
0
30
c
0
20
10
Q
M P` CO a) o r N M Re Ln W P` CO a) 0 r N M � Ln
N N N N M M M ►°7 M M M M M M Re Re Re Ile Ile Ile
0 0 0 0 0 0 0 0 0 0 0 0 o C 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
Avista Corp 2025 Natural Gas IRP 66

Chapter 3: Demand Forecast
Customer Electrification Forecast
Avista includes two types of electrification decision making within this IRP. The first is
electrification initatied by Avista. This electrifcation is selected within the PRS modeling
to meet either load or state enivormental policy. The second form of electrificaiton is the
organic electrifcication from customer choice. Avista assumes some customers will
choose electrification of appliances during new constuction or retrofit of their building. The
demand forecast only includes customer driven electrifcation decisions, where a
customer has the option to replace the existing natural gas space or water heating
equipment with electric alternatives, and includes purchase decision logic copied from the
U.S. DOE's National Energy Modeling System. The conversion costs include the
possibility of an electric panel upgrade and associated labor. The model compares the
lifetime cost of ownership including lifetime fuel costs, upfront costs and associated labor
along with the tax benefits form the Inflation Reduction Act (IRA), but do not include any
state incentives (as these are not known). Figures 3.9 to 3.14 show the amount of demand
reduction expected to occur naturally by jurisdiction for residential and commercial
customers.
Figure 3.9: Idaho Residential - Load Reduction Occurring Naturally
0
-1 00,000
-z00,000
-300,000
r
o -400,000
-500,000
-600,000 Appliances
-700,000 m Space Heating
■Water Heating
-s00,000
M r- CO cM o r N MIt* Ln M r- 00 M c r N M qe un
N N N N M C7 M n M M M M M M R qe Re qe Iq
CD CD 0 0 0 0 CD CD CD CD CD CD CD CD CD CD CD CD CDC
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 67

Chapter 3: Demand Forecast
Figure 3.10: Oregon Residential - Load Reduction Occurring Naturally
0
-50,000
-1 o0,000
-150X0
o -200,000
-250,000
-300,000 Appliances
-350X0 ■ Space Heating
Water Heating
-400X0
CD r` 00 a) C r N C`'M I"? kO CD r` CO C C r N n lqt ►Y9
C C C C C C C C C C C C C C C C C C C C
N N N N N N CV C 4 CV CV N N N N N N N N N N
Figure 3.11: Washington Residential - Load Reduction Occurring Naturally
0
-200X0
-400X0
-so0X0
o -800,000
-toK000
-1I 200,000 Appliances
-1,400,000 m Space Heating
Water Heating
-ts00,o00
CO r` 00 a) C r N (n ? LO CD r` CO C C r N 01 qr LO
C C C C C C C C C C C C C C C C C C C CD
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 68

Chapter 3: Demand Forecast
Figure 3.12: Idaho Commercial - Load Reduction Occurring Naturally
D
-1 DD,DOD
-zDD,DDD
o -3DD,DDD
-4DD,DDD
Food Preparation
-SDD,DDD ■Space Heating
-soo,Doo ■Water Heating
W r` CO C7 C r N M qe LO C t` CO C) C r N M Re LO
N N N N M M M M M M M M M Mlie v Re Re Re Re
C C C C C C C C C C C C C C C C C C C C
N N N N N N N N N N N N N N N N N (N N N
Figure 3.13: Oregon Commercial - Load Reduction Occurring Naturally
D
-1 DD,00D
-zDD,00D
-3DD,DDD
-4DD,00D
-500,DDD Food Preparation
-600 DDD ■Space Heating
-700,000 ■Water Heating
W r` CO C) C r (N M19t Ln C r` CO d) C r N M V Ln
N N N N M M M M M M M M M M v R* v v v
C C C C C C C C C C C C C C C C C C C C
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 69

Chapter 3: Demand Forecast
Figure 3.14: Washington Commercial - Load Reduction Occurring Naturally
0
-100,a00
-z00,o00
o -300,000
-400,000
Food Preparation
-500,000 ■Space Heating
-600,000 ■Water Heating
W r` CO C7 C r N M qe LO C t` 00 OA C r N M qe LO
N N N N M M M M M M M M M M qe V V V V Re
C C C C C C C C C C C C C C C C C C C C
N N N N N N N N N N N N N N N N N N N N
Idaho is the only state with an expected increase in customers, specifically in the
residential and commercial classes. With a 1.64% average customer growth rate, the
residential class in Idaho has the fastest growth, followed by the commercial class with
an average growth rate of 1.5%. The average customer growth rates in Oregon are 0.46%
for residential customers and 0.37% for commercial customers. Washington follows a
more muted trend of customer growth rates of 0.04% for residential customers and 1.35%
in the commercial class. Industrial customers in Idaho and Oregon have a negative
growth rate while Washington is nearly flat at 0.005%.
Although some of these classes estimate some growth, the overall energy use is
expected to be declining in Oregon and Washington (-0.31% and -1.68%) with a slight
average increase of 0.37% across firm customer classes in Idaho as shown in Table 3.2.
Table 3.2: Annual Average Demand Change by State (2026-2045)
State Residential Commercial Industrial Total
Idaho 0.18% 0.74% -0.13% 0.37%
Oregon -0.37% -0.23% -0.06% -0.31%
Washington -0.98% -1.70% -0.06% -1.68%
System -0.65% -0.98% -0.09% -0.76%
The primary cause for decreased load in most jurisdictions can be explained through
energy intensity. It is a use per customer metric where demand over time is measured
per customer or unit (square feet). It considers upgrades of equipment and building shells
Avista Corp 2025 Natural Gas IRP 70

Chapter 3: Demand Forecast
along with end use technology efficiency gains from higher building code standards and
a change in future temperatures. When viewed over the forecast period it produces a
declining use per customer as shown in Figures 3.15 to 3.16.
Figure 3.15: Residential Customers Energy Intensity per Customer in Washington
800
700
:2 600
0
500
c 400
= 300
E- 200
a�
100
2026 2030 2035 2040 2045
❑ Space Heating ❑ Water Heating ❑ Secondary Heating
❑ Appliances ■ Miscellaneous
Figure 3.16: Commercial Energy Intensity (Therms/Sgft) in Washington
0.90
0.80
0.70
0.60
Cr
U) 0.50
E 0.40
0.30
0.20
0.10
2026 2030 2035 2040 2045
❑ Space Heating ❑ Water Heating ❑ Miscellaneous ❑ Food Preparation
Avista only includes transportation tariff customer demand for emissions compliance
programs in Oregon and Washington. This demand excludes transport customers larger
than 25,000 metric tons of carbon dioxide equivalent (MTCO2e) in Washington and those
Avista Corp 2025 Natural Gas IRP 71

Chapter 3: Demand Forecast
specific customers removed in the final rules of the CPP larger than 15,000 MTCO2e.
Avista then uses the average demand based on the three years of monthly historic
demand in Oregon and Washington. Figure 3.17 is an example of demand for transport
customers used in this plan. Beginning in 2026, monthly demand is carried forward for
the forecast horizon as the gross demand prior to energy efficiency.
Figure 3.17: Monthly Demand of Transport Customers (MMBTU)
400
350
0
0 300
250 / \
0200
s 150 •J
~ OR Transport
100 WA Transport
50 2025 IRP Transport Load - OR
2025 IRP Transport Load - WA
N Cn LO CO
N N N N N N
C C C C C C
fC fC fS3 fQ fC fC
Weather Forecast
The weather forecast is a critical piece of the planning process. It is used to calculate
expected demand by planning area when combined with use per customer and number
of customers and it drives the resource strategy selection to meet energy and emissions
requirements. The 2025 IRP combines historic temperatures and a temperature forecast
to create a daily temperature by planning area. These sets of historic and forecasted
temperature data are then used to create a design day peak.
Historic Temperature
The most current 20 years of daily weather data (minimums and maximums) from the
National Oceanic and Atmospheric Administration (NOAA) is used to compute an average
for each day. NOAA data is obtained from five weather stations, corresponding to the
areas where Avista provides natural gas services (four in Oregon and one for Washington
and Idaho), where this same rolling 20-year daily average weather computation is
completed for all five areas. A comparison of a rolling 20-year average from 2004 and
2023 is illustrated in Figure 3.18. The Oregon weather stations in Roseburg and Medford
have correlated weather patterns, while those in the Klamath Falls and La Grande areas
are uncorrelated. HDD weather patterns amongst eastern Washington and northern
Idaho portions of the service area are also correlated.
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Chapter 3: Demand Forecast
Figure 3.18: 20 Year Rolling Average by Weather Station
10,000
11111111111111111111120 year rolling avg -2004 -2023 . Max of 20 Years
9,000
8,000
�1
7,000
6,000
N
p 5,000
2
4,000 7,686
6,966 6,937
3,000
2,000 4,960 4,622
1,000
Klamath Falls La Grande Medford Roseburg Spokane
The NOAA 20-year average weather serves as the base weather forecast to prepare the
annual average demand forecast. The peak day demand forecast includes adjustments
to average weather to reflect a five-day cold weather event.
Forecasted Temperatures
There is significant uncertainty in projecting future temperatures and precipitation. This
IRP uses temperature forecast data from Oregon State University's Institute of Natural
Resources and uses a Multivariate Adaptive Constructed Analogs (MACA)'. The MACA
method is a statistical downscaling method for removing biases from global climate model
outputs. The MACA dataset is unique due to how it downscales a large set of variables
(temperature, precipitation, humidity, wind, radiation) making it ideal for different kinds of
modeling of future temperatures (i.e., hydrology, ecology, vegetation, fire, wind). These
models also include representative concentration pathways (RCPs). 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 following scenarios:
• RCP 2.6 — stringent GHG mitigation scenario
• RCP 4.5 & RCP 6.0 — intermediate GHG scenarios
• RCP 8.5 — very high GHG scenarios.
MACA Statistical Downscaling Method
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Chapter 3: Demand Forecast
Table 3.3 provides a comparison of the temperature increases projected under the
various scenarios by RCP.
Nip %.%o,,,1jcAson of Tei„N�,aLu11-- Increases by RCP
- . 0. 08
Scenario
Nllea@� Likely range Mean a Likely range-V
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.
Avista selected modeling results based on the RCP 4.5 for this IRP due to:
• RCP 8.5 is at the high end of potential future GHG emissions,
• there are significant worldwide efforts to mitigate GHG emissions,
• the intermediate scenarios are similar during the IRP planning horizon,
• using RCP 4.5 temperatures for planning protects against the risk of the future not
warming as anticipated,
• RCP 4.5 and 8.5 have overestimated winter temperatures on average (except for
January).
Avista applied this information using the following methods:
• Median HDD values of available studies by planning region, using the average of
daily min/max.
• Trended HDDs from 2026 to 2045 to calculate an average increase or decrease
over the planning horizon.
• Rolling daily 20-year blend (historic and MACA HDDs).
MACA 4.5 and 8.5 weather median futures trended from 2026 to 2045 by planning area
and combine with historical actual data into a rolling 20-year average. In the absence of
a RCP 6.0 climate future, an average of the 4.5 and 8.5 models were used to produce a
proxy for a RCP 6.5 scenario. Each planning region is entered by longitude and latitude
with the data extracted corresponds to the average over the grid cell that contains your
selected point. MACA 4.5 and MACA 6.5 represent growth in greenhouse gas emissions,
but the growth is lower in comparison to RCP 8.5 due to mitigation strategies. Warming
temperatures will impact average demand yet Avista maintains a severe cold weather risk
and requires flexible resources to meet these extreme temperatures in each planning
area. Specifically, we expect less heating demand in the winter.
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Chapter 3: Demand Forecast
A 20-year moving average of the HDDs is used, combining the historical and forecasted
temperatures. In this analysis, the median daily average temperature of the MACA
models isa used as the temperature data set compared to the 20-year moving average
for each forecast year. Figure 3.19 shows the HDDs used by year and by planning region
under RCP 4.5. The overall impact is hard to distinguish in a line chart so to help with this
we have included Figure 3.20 showing the overall decrease from 2026 to 2045.
Figure 3.19: RCP 4.5 Blended with 20 Year Historic Temperatures
9,000
8,000
7,000
0 6,000
0
= 5,000
c
4,000
a 3,000
2,000
Klamath Falls La Grande
1,000 Medford Roseburg
Spokane
cD r~ CO M O N M qt LO W ti 00 a) O N M qt LO
N N N N M M M M M M M M M M q1 � � 'Rt 11 '9t
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
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Chapter 3: Demand Forecast
Figure 3.20: 20-Year Decrease of HDDs by Planning Region
250
0 200
m c 150
q> N
M O
� � 1
c 100
L N
0 50
N
Klamath La Grande Medford Roseburg Spokane
Falls
Peak Day Design 'emperature
The weather planning standard is an important piece of system planning for resources in
an IRP because it sets the amount of firm delivery requirements to procure or construct.
For most historical IRPs, the coldest day on record was used as the design day. In the
2023 IRP, Avista attempted to include future temperature forecasts within its design day
calculations. For this IRP, the design day methodology is further evolved by calculating
the design day by taking the coldest day on record for each area and adjusting it based
upon the RCP 4.5 annual expected change in temperatures over the next 20 years. This
temperature adjustment is shown in blue within Figure 3.21 for the Medford weather
station. The orange line represents the coldest day on record, while the grey line is the
99th percentile coldest day from the MACA weather future temperatures between 2026
and 2045.
The 99th percentile, or 1-in-100 events, temperature forecast is colder than Avista's
design day temperature for all locations. This temperature implies there is potential for
overall HDDs to increase when comparing the historical coldest day on record according
to global climate models. Given this uncertainty in projecting future temperatures, Avista
will continue to improve upon its design day methodology in future IRPs. Table 3.4 is a
summarizes each areas design day temperature in 2045, the current coldest day on
record, and the 99th percentile coldest day of the weather futures from global climate
models assuming RCP 4.5.
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Chapter 3: Demand Forecast
Figure 3.21: Medford Weather Station —Weather Planning Standard Comparison
66
64
62
0 60
0
Y 58
c�
a 56
54 COR less avg. weather decrease
52 —Coldest on Record
—99% probability based on weather futures
50
C0 r~ 00 (M O T- N CO Iq LO CD r` 00 O O T­ N CO Iq V)
N N N N M M M M M M M M M M 'q � NT 'q � �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Table 3.4: Peak Day Design Temperature
Coldest on Record q9th Percentile Coldest 2045Design D.
(Prior IRP's) Day Forecast
La Grande -10 -19 -8.0
Klamath Falls -7 -14 -6
Medford 4 1 5
Roseburg 10 1 12
Spokane -17 -24 -14
Beyond a single cold day, the weather planning standard utilizes a five-day cold weather
event by service territory while adjusting the two days on either side of the planning
standard to temperatures colder than average. For the Washington, Idaho, and La
Grande service territories, the model assumes this event on and around February 28t"
each year to safeguard the availability of storage resources to serve customers in late
season cold weather events. With pipeline and storage resources in the Pacific Northwest
constrained, managing supply along with the ability to serve cold days is paramount. For
the southwestern Oregon service territories (Medford, Roseburg, and Klamath Falls), the
plan assumes this event occurs on and around December 20t" each year.
When considering changing weather in our service territories, a historic comparison is
helpful as shown in Figures 3.22 to 3.26. This Z-statistic analysis is used to compare the
deviation from an average temperature over each stated timeframe. Distributions of these
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Chapter 3: Demand Forecast
daily changes compared to the average daily weather over the timeframe will emerge.
The Spokane weather area maintains the same shape from a reference period where the
coldest on record set of temperatures occurred. A slight deviation to the positive side of
the Z-statistic points to a general warming trend compared to the reference period.
Movement towards the right on the X-axis points to an increased deviation compared to
the reference period indicating a shift to warmer weather. These figures illustrate a period
of 30-year weather compared to recent weather by planning region for December,
January, and February. An important piece of this analysis is to determine the tail to the
left of each graph as this confirms cold weather is still occurring as seen historically.
Figure 3.22: Spokane Historical Temperature Distribution
30%
'51/'52=80/'81 Reference Period
25% — '01/'02=23/'24 Period
20%
a
15%
a
Ui 10%
5%
o LO o LO o In o LO o LO o U) oUI) o U1 o U1 o Wn o
Ui M M N N O O O N N M M 14 .4 Un
I I I I I I
Z-Stat
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Chapter 3: Demand Forecast
Figure 3.23: Medford Historical Temperatures
0
° — '51/'52-'80/'81 Reference Period
'01/'02 - '23/'24 Period
25%
20%
15%
a
U.
10%
5%
0%
6 M CM N N o 6 6 N N M M 14 .4 L6
Z-Stat
Figure 3.24: La Grande Historical Temperatures
30% — '51/'52=80/'81 Reference Period
'01/'02=23/'24 Period
25%
20%
v 15%
c
a)
a 10%
m
L
LL
5%
o LO o LO o LO o LO o LO o LO o LO o LO o LO o LO o
�1 M M N N o 6 6 N N M M -4 -4 Ui
Z-Stat
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Chapter 3: Demand Forecast
Figure 3.25: Klamath Falls Historical Temperatures
30% _ '51/'52-'80/'81 Reference Period
'01/'02-'23/'24 Period
25%
20%
v 15%
c
W
10%
u-
5
0%
w
o Ln o Ln o Ln o Ln. o. Ln o in o. in. o in o Ln o Ln o
Ui. 1 'i C"i C"i N N O O O . . M. M. 'i --i 6
Z-Stat
Figure 3.26: Roseburg Historical Temperatures
30%
'51/'52-'80/'81 Reference Period
25% '01/'02-'23/'24 Period
20%
c 15%
as
Cr
10%
u_ `
5%
0%
o Ln o Ln o Ln o Ln o Ln o uo o Wn o Wn o Ln o Ln o
Ui M M N N W. V. O O O N N M M 14 .4 In
Z-Stat
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Chapter 3: Demand Forecast
Weather Stochastics
Avista developed 500 simulations (draws) to evaluate weather and its effect on the
portfolio. Unlike deterministic scenarios or sensitivities, the stochastic draws have more
variability from month-to-month and year-to-year. In the model, random monthly total
HDD draw values (subject to Monte Carlo parameters — see Table 3.5) are distributed on
a daily basis for a month in history with similar HDD totals. The resulting draws provide a
weather pattern with variability in the total HDD values, as well as variability in the shape
of the weather pattern. This provides a more robust basis for stress testing the
deterministic analysis. These inputs are derived from the expected monthly temperatures
from 2026 to 2045 as discussed above as the HDD mean, min and max. Historic
temperatures are used as the standard deviation of these values as there is more data to
draw information from with actual temperature variation to measure these mean HDD
expectations variability.
Table 3.5: Example of Monte Carlo Weather Inputs — Spokane
DecNov -. Mar Apr May Jun Jul Aug Sep Oct
HDD Mean 867 1,110 1,170 935 799 541 318 140 31 40 194 523
HDD Std Dev 111 133 179 129 99 87 81 51 26 31 73 86
HDD Max 1,374 1,519 1,759 1,389 1,059 740 494 260 168 144 363 695
HDD Min 609 839 850 703 561 269 146 12 - - 59 334
The model considers five weather areas: Spokane, Medford, Roseburg, Klamath Falls
and La Grande. See Figure 3.27 through Figure 3.31 for the number of annual heating
degree days by weather area. These distributions help stress test the model for different
load profiles and needed resources based on varying weather. These Monte Carlo
simulations combine weather futures and historic data to obtain randomly generated
weather events.
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Chapter 3: Demand Forecast
Figure 3.27: Frequency of Annual HDDs (2026-2045) — Spokane
80
70
60
50
a
40 ,
a,
LL. 30
20
10
0
Q1 00 n lD lf1 � M N e-i O Q1 00 n
M M rI% tD 0 RZI, M N rl O M r\ tD 0 TI, M N rl O M
�f1 tD 00 Q1 O r-I N M TT 0 tD r\ 00 M O r-I N N
111 ll1 111 ll1 111 tD tD tD tD lD tD tD tD tD tD tD r\ n n n
O (3 00 r\ tD Lr -:: M rV e-I O U 00 r\ tD tf1 zi ry r1 e-I
rl M M r%% t0 0 Rzr M N rl O M rI% tD 0 Itzr M N rl O
lf1 ll1 t0 n 00 Q1 O rl N M Ill tD r\ 00 M O rl N
111 111 111 ll1 111 ll1 lD lD lD lD lD lD lD lD lD lD la � �
Figure 3.28: Frequency of Annual HDDs (2026-2045) — Medford
80
70
60
50
a
40
v
30
20
10
0
r\ N FX Q1 ll1 e-i tD f V 00 M Q1 �j O tD rl F M 00 �j
0 rV M 0 rl M 0 rl M Itzr rl r\ TT rl f\ Itzr O r\ M O
M O O rl N N M q* I:T 0 tD tD r\ M 00 M O O r-I N
rI r\ r" 00 -:i ci Lr e--I tD rV 00 ry ci zi O tD e--1 n M 00
M 0 N M 0 rl M Ln rI M 11:11 `--I rI% Itzr r--I r� Izr O r.% M
00 M O O '-A N N M I:T I::r 0 tD tD r\ 00 M M O O rl
M M qr lzr qr I:zr lqr ItT qr lzr qr Irr lqr Irr Irr Irr I::r 0 Ln 0
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Chapter 3: Demand Forecast
Figure 3.29: Frequency of Annual HDDs (2026-2045) — Roseburg
90
80
70
60
50
40
30
20
10
0
tD r-I tD r-I n N n N n N n N n N 00 M 00 M 00 M
0 rV 00 0 r-I 00 Itzr r-I rI% Itzr O r\ M O to M M tD N M
M O O r-I N N M IZT I:T 0 tD tD r\ M M M M O r-I r-I
M I:zr lqr I:zr lqr I:zr qr lqr lqr lzr lzr lzr lqr Rzr RI, qzr q:3, Ln Ln Ln
ri tD e--I tO e--I r\ f V n f V n f V r\ (, r\ (, 00 fy 00 ry 00
M 0 N 00 0 r-I 00 Itzr r-I r%% Tzr O rI% M O tO M M tD N
00 M O O r-I N N M "ZT IZT Ln tD tD r\ 00 M M M O r-I
M M I:ZT 1::r lqr I:zr lqr TT lzr Izr lzr Izr lzr TT lqr lzr lqr Irr Ln Ln
Figure 3.30: Frequency of Annual HDDs (2026-2045) — Klamath Falls
80
70
60
50
40
v
U- 30
20
10
0
r-I Ql 7M r-I Ol ll1 N O 00 lD N O 00
n 111 qr M N r-I m 00 r\ tD 111 qr N ri O m w tD 111 r
O r-I N M Irr Ln Ill tD t\ w M O r-I N M M I::r Ill tD t\
tD lD lD tD tO tD tO tO tD tD tD N n r\ r\ r\ n r\ r\ r\
M r-I Ql r\ LPG M 1 cr r\ Lr1 -:i N O 00 1. -:i N O 00 tD
00 r\ Ln ItZr M fV r-I M 00 r\ tD Ln 'Zr N r-I O M 00 tD Ln
M O r-I N M Tzr Ill Ill tD t\ 00 M O r-I N M M I:T Ill tD
111 'D tD lD lD tD tD tO tD tO tD lD n n n n n n n n
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Chapter 3: Demand Forecast
Figure 3.31: Frequency of Annual HDDs (2026-2045) - La Grande
80
70
60
c
50
r
40
r
,i 30
20
10
0
.--, ,--, ,--, ,--,
N O N Ln M rl M w 4 N O w Ln M r1 M N � N O
� M rl O M 00 w LM M N O M 00 N Ln M N r-I
QD N 00 M M O r--I N M 'qr Ln w w N 00 M O r--I N M
Ian � M .^-I O C1 00 w IOA M N O M 00 N Ln 9 M N
Ill w r% 00 C1 C1 O rl N en RT Ill %D %D N 00 C1 O rl N
Load Forecast
The combination of the elements discussed in this chapter produces an estimated energy
need as illustrated in Table 3.6. The forecast is broken out by jurisdiction, separated by
firm and transport only expectations. This represents the expected loads used in the
Preferred Resource Strategy (PRS) and includes the reduction in demand from energy
efficiency.
Table 3.6: Lnacl Fnrecast (Thousand Dekatherms)
OregonYear Washington Washington
M =�w Transport Transport Firm w/Transport
2026 20,307 10,377 8,823 3,181 2,603 39,507 45,291
2027 20,063 10,401 8,749 3,159 2,586 39,213 44,958
2028 19,695 10,396 8,661 3,137 2,569 38,752 44,458
2029 19,216 10,389 8,545 3,114 2,551 38,150 43,815
2030 18,760 10,373 8,441 3,090 2,531 37,574 43,195
2031 18,239 10,321 8,320 3,066 2,510 36,880 42,456
2032 17,808 10,319 8,224 3,041 2,489 36,351 41,881
2033 17,335 10,289 8,102 3,017 2,467 35,726 41,210
2034 16,910 10,286 7,993 2,994 2,445 35,189 40,628
2035 16,558 10,325 7,922 2,972 2,424 34,805 40,201
2036 16,203 10,364 7,853 2,952 2,405 34,420 39,777
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Chapter 3: Demand Forecast
2037 15,777 10,333 7,734 2,936 2,388 33,844 39,168
2038 15,393 10,345 7,614 2,921 2,373 33,352 38,646
2039 14,975 10,327 7,479 2,909 2,360 32,781 38,050
2040 14,644 10,363 7,379 2,897 2,347 32,386 37,630
2041 14,331 10,398 7,266 2,886 2,336 31,995 37,217
2042 13,970 10,391 7,137 2,878 2,326 31,498 36,702
2043 13,717 10,455 7,025 2,869 2,315 31,197 36,381
2044 13,468 10,515 6,928 2,860 2,306 30,911 36,077
2045 13,151 10,509 6,781 2,846 2,289 30,441 35,576
The peak demand forecast, net of energy efficiency, is included in Table 3.7. This forecast
is analyzed to measure capacity needs on a peak day by demand area. Firm service
customers rely on this capacity on the coldest of days to deliver the necessary energy to
keep customers and their assets safe.
Table 3.7: Peak Day Load Forecast by Area (Thousand Dekatherms)
TransportWashington Idaho Oregon Washington Oregon Total Total w/
. • rTransport
36 2026 238.13 1 .61 101.43 8.61 8.34 476.17 493.12
2027 233.66 136.56 100.28 8.56 8.31 470.50 487.37
2028 229.11 136.41 99.09 8.20 8.00 464.61 480.81
2029 224.69 136.79 97.89 8.43 8.25 459.37 476.06
2030 220.13 136.74 96.58 8.37 8.22 453.45 470.03
2031 215.52 136.63 95.22 8.30 8.18 447.37 463.85
2032 210.91 136.48 93.83 7.95 7.87 441.22 457.04
2033 206.35 136.34 92.40 8.17 8.11 435.09 451.38
2034 201.87 136.17 90.94 8.11 8.07 428.98 445.16
2035 197.54 136.05 89.45 8.05 8.04 423.04 439.12
2036 193.35 135.99 87.93 7.72 7.73 417.26 432.71
2037 189.36 136.00 86.37 7.95 7.98 411.73 427.66
2038 185.53 136.07 84.78 7.91 7.95 406.38 422.24
2039 181.84 136.18 83.16 7.88 7.93 401.18 416.99
2040 178.31 136.32 81.53 7.58 7.64 396.16 411.37
2041 174.98 136.51 79.87 7.82 7.89 391.36 407.06
2042 171.75 136.69 78.18 7.79 7.87 386.62 402.29
2043 168.69 136.91 76.47 7.77 7.85 382.07 397.69
2044 165.75 137.12 71.02 7.48 7.57 373.89 388.93
2045 162.98 137.36 69.25 7.72 7.82 369.60 385.14
Scenario Analysis
Demand is becoming more difficult to forecast due to the policy updates in both Oregon
and Washington and building code updates in Washington. Changes in total demand can
drastically change both the timing and resources selected, making it necessary to look at
different future expectations based on demand, costs, and resource availability. Table 3.8
identifies the scenarios and sensitivities developed for this IRP. The PRS reflects the
Avista Corp 2025 Natural Gas IRP 85

Chapter 3: Demand Forecast
expected demand and available costs and resources Avista believes is most likely given
expected peak weather conditions. All other scenarios represent a different set of future
expectations and range of possible outcomes based on current policies, codes, and
customer demand. Each scenario provides a "what if' analysis of a different future
assumption given the volatile nature of key assumptions, including weather and price.
Table 3.8: Demand Scenarios and Sensitivities
Preferred Resource Strategy Scenario — Our High Customer Scenario — A high demand
expected case based on assumptions and costs case to measure risk of additional customer
with a least risk and least cost resource selection and meeting our emissions and energy
obligations
High Electrification Scenario — Scenario to show Average Case Sensitivity — Non climate
the risk involved with energy delivered through the change projected 20-year history of average
natural gas infrastructure moving to the electric daily weather and excludes peak day
system
Hybrid Heating Scenario — Natural Gas used for Low Natural Gas Use Scenario — A lower
space heat below 380 F while transferring all other than expected use case using RCP 8.5
usage to electricity. weather futures along with high costs for
compliance
RCP 8.5 Weather Sensitivity — Expected case RCP 6.5 Weather Sensitivity - expected
scenario assumptions with RCP 8.5 weather case scenario assumptions with RCP 6.5
futures. weather futures.
Initiative 2066 Sensitivity — Expected case No Growth —no new customers in OR&WA
assumptions with a pause of Washington State after line allowances expire in 2026 and 2025,
commercial customers loads building codes. respectively.
The total estimated system loads across scenarios and sensitivities address starkly
different load scenarios as shown in Figure 3.32 and further discussed in 'hanter 8, these
forecasts include energy efficiency. RCP 6.5 and 8.5 sensitivities follow closely with the
PRS scenario and are hard to distinguish in the figure within the forecast horizon and
alternative loads. These loads encapsulate varying plausible futures and potential
outcomes based on shifting policies, standards, and possible incentives. These policies
are further discussed in Chapter 8.
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Chapter 3: Demand Forecast
Figure 3.32: System Load Forecast by Scenario/Sensitivity
50
45
40
35
30
0
25 --O—PRS -,--All Others (same load)
C Average Use
20 High Electrification
High Growth
15 Hybrid Heating
RCP 8.5
10 RCP 6.5
5 Social Cost of Carbon
1 2066
No Growth
c fl 1` oo M O N M Kt u') cD r— oo M O N M —r LO
N N N N M M M M M M M M M M � � � IIqr IIqr
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 3: Demand Forecast
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Chapter 4: Demand Side Resources
4. Demand Side Resources
Section Highlights:
• Energy efficiency is expected to offset 11% of demand by 2045.
• Heat pumps can provide great efficiency, but conversion costs remain a primary
barrier.
• Higher avoided cost in Oregon and Washington drive higher efficiency targets
compared to Idaho.
Avista is committed to offering natural gas energy efficiency (EE) programs to residential,
low income, commercial, and industrial customer segments when it is feasible and cost-
effective within each jurisdiction. Avista began offering natural gas EE programs in 1995.
Program delivery has grown over the years with an emphasis on increasing customer
participation. Avista's program design includes both prescriptive and site-specific
offerings. Recent expansion includes additional programs such as On-Bill Repayment,
Home Energy Audits, and incentives offered through midstream channels. Programs are
designed to provide cash incentives for products such as the installation of qualifying high
efficiency heating equipment, building weatherization, smart controls, and data informed
approaches to saving energy.
Over the years, Avista has seen the most significant impacts in the residential market with
the installation of high efficiency HVAC measures, such as furnaces, tanked and tankless
water heaters, and the use of smart thermostats. These programs have historically
produced the highest levels of EE, however, Avista strives to continue offering programs
appealing to all customer segments. With the introduction of the House Bill 1444 in
Washington, known as the Clean Buildings Act, Avista anticipates more non-residential
programs and increased participation in the future.
Avoided Cost
The preliminary cost-effective EE potential is determined by applying the stream of annual
natural gas avoided costs to the Avista-specific supply curve of EE resources. These
costs include commodity costs, distribution deferral values, storage costs, social cost of
greenhouse gas at the 2.5% discount rate (Washington only), fuel costs to move the
natural gas from point A to point B, and a 10% preference adder for EE for Washington
and Oregon among others discussed in JaN«l - .
Avista's contractor, Applied Energy Group (AEG), for Idaho and Washington, with input
from Avista's EE team, determines the initial technical EE acquisition values through the
Conservation Potential Assessment (CPA) process, and the Energy Trust of Oregon
(ETO) handles this process for Oregon for non-transport customers. The initial estimates
from AEG and ETO are then decremented from Avista's load forecast. As the model
changes based on updated assumptions and costs, updated avoided costs are
Avista Corp 2025 Natural Gas IRP 89

Chapter 4: Demand Side Resources
considered by AEG and ETO to calculate the cost-effective EE potential within Avista's
service territories, also known as economic potential. In Oregon and Washington, cost-
effectiveness is calculated using the Total Resource Cost (TRC) methodology and in
Idaho the Utility Cost Test (UTC) methodology is used. These methodologies are
described below. Cost effective EE measures reduce customer demand and provide
benefits by avoiding commodity, storage, transportation, and other supply resource costs
while reducing the risk of unserved demand in peak weather.
The avoided-cost values represent the unit cost to serve the next incremental unit of
demand with a supply-side resource option during a given period. CROME calculates
marginal cost data by day, month, and year for each demand area. A summary graphical
depiction of avoided winter costs for each jurisdictional area is in Figure 4.1.
Figure 4.1: Residential Winter Avoided Cost (By Jurisdiction)
$20
$18
$16
$14
$12
$10
a $8
$6
$4
$2 ID-Res OR-Res WA-Res
to I- CO O O r N M � to to I- CO O O N M I In
N N N N M M M M M M M M M M le le le � Iq �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
LO t0 I- 00 O O � N M Iq uO tD Il- 00 O O � N M Iq
N N N N N M M M M M M M M M M le Iq le Iq Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Winter Months (Nov-Mar)
Idaho and Washington Conservation Potential Assessment
As part of its process for identifying its CPA, Applied Energy Group (AEG)was contracted
to perform an independent CPA for Washington and Idaho natural gas. The CPA is
Avista's tool to identify the level of EE it anticipates achieving over a 20-year period.
Moreover, the CPA is used to identify the EE target for each jurisdiction. The entire CPA
report including the methodology used can be found in Appendix 4.
AEG's CPA report documents this effort and provides estimates of the potential
reductions in annual energy usage for natural gas customers in Avista's Washington and
Idaho service territories from EE efforts from 2026 to 2045. To produce a reliable and
Avista Corp 2025 Natural Gas IRP 90

Chapter 4: Demand Side Resources
transparent estimate of EE resource potential, the AEG team performed the following
tasks to meet Avista's key objectives:
• Used information and data from Avista, as well as secondary data sources, to
describe how customers currently use natural gas by sector, segment, end use
and technology.
• Develop a baseline projection of how customers are likely to use natural gas
absent future EE programs.
• Define the metrics future program savings are measured against. This projection
used up-to-date technology data, modeling assumptions, and energy baselines
that reflect both current and anticipated federal, state, and local EE legislation that
will impact EE potential.
• Estimate the technical, achievable technical, and achievable economic potential at
the measure level for EE within Avista's service territory over the 2026 to 2045
planning horizon.
• Focused on the potential study to provide a solid foundation for the development
of Avista's energy savings targets.
Pursuing Cost-Effective Energy Efficiency
Avista's approach is to pursue all cost-effective EE with reliable and feasible program
opportunities for the benefit of our customers and the system. Resource planning relies
on the EE program's ability to reach its targets but also to ensure they contribute to an
optimized strategy of providing the lowest cost resource.
Cost-effectiveness analysis considers the net benefit derived from EE programs with both
the definition of "benefits" and "costs" differing between jurisdictions. The cost-
effectiveness of EE programs can be viewed from a variety of perspectives, each of which
leads to a specific standardized cost-effectiveness test. The section below outlines and
describes various perspectives.
'otal Resource Cost T__
Total resource cost (TRC) is from the cost perspective of the entire customer class of a
particular utility. This includes not only what customers individually and directly pay for
efficiency (through the incremental cost associated with higher efficiency options) but also
the utility costs customers will indirectly bear through their utility bill. The TRC considers
the impacts from energy benefits, non-energy benefits, greenhouse gas emission costs,
administrative costs, and the incremental costs between standard and high efficiency
equipment.
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Chapter 4: Demand Side Resources
Utility Cost Test
1. The Utility Cost Test (UCT) or Program Administrator Cost Test (PAC) compares the
reduced utility avoided cost and the full cost (incentive and non-incentive cost) of
delivering the utility program.
2. As part of the CPA, each cost test is applied according to the jurisdiction's primary
cost test methodology. Idaho uses the UCT while Oregon and Washington use a
modified TRC Test.
Washington and Idaho Energy Efficiency Potential
First-year TRC achievable economic potential in Washington is 92,492 dekatherms. This
increases to a cumulative total of 197,255 dekatherms in the second year and 1,950,280
dekatherms by 2045. Figures 4.2 to 4.5 summarize the results for Avista's Washington
service territory by customer class. In these figures EE savings are cumulative for all prior
years in the study and the costs are based on the annual cost estimate by year. AEG
analyzed EE potential for all segments in the residential, commercial, industrial and
transportation classes where Avista has obligations for compliance with the Climate
Commitment Act (CCA) as discussed in ,hapter i .
rigure 4.2: Washington Residential - Energy Efficiency Savings and Costs
0.80 3.500
TWA-Res Cum
0 0.70 Savings (Dth) 3.000
0 0.60 —WA-Res Total Utility
Cost ($million) 2.500
0.50
2.000 c
0.40
M 1.500
0.30
m 0.20
1.000
v0.10 0.500
0.00 0.000
2026 2027 2030 2035 2040 2045
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Chapter 4: Demand Side Resources
Figure 4.3: Washington Commercial - Energy Efficiency Savings and Costs
1.00 2.000
1 WA-Com Cum
0.90 Savings (Dth) 1.800
0.80 WA-Com Total Utility 1.600
:0 0.70 Cost ($million) 1.400
N 0.60 1.200 0
M
•S 0.50 1.000 or_
M o
M 0.40 0.800
a�
•> 0.30 0.600
M
= 0.20 0.400
U 0.10 0.200
0.00 0.000
2026 2027 2030 2035 2040 2045
Figure 4.4: Washington Industrial - Energy Efficiency Savings and Cost
0.04 0.060
WA-Ind Cum Savings (Dth)
o —WA-Ind Total Utility Cost ($million)
0.050
0 0.03
0.040
cn O
a�
0.02 0.030 '
M o
M _
> 0.020
0.01
E 0.010
U
0.00 0.000
2026 2027 2030 2035 2040 2045
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Chapter 4: Demand Side Resources
Figure 4.5: Washington Transport - Energy Efficiency Savings and Costs
0.40 0.250
llllllllllliiiiiiiiiliiiiiWA-Tprt Cum Savings (Dth)
0 0.35 WA-Tprt Total Utility Cost ($million)
0.200
o 0.30
0.25 0.150 4-
cn o
0.20
M o
0.15 0.100
z
M 0.10
0.050
v 0.05
0.00 0.000
2026 2027 2030 2035 2040 2045
First-year UCT achievable economic potential in Idaho is 26,257 dekatherms. This
increases to a cumulative total of 60,181 dekatherms in the second year and 600,730
dekatherms by 2045. Figure 4.6 summarizes results for residential customers in Avista's
Idaho service territory for both cumulative savings in dekatherms (Dth) and annual costs.
Figure 4.7 shows the same metrics for commercial customers and Figure 4.8 shows the
results for industrial customers.
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Chapter 4: Demand Side Resources
Figure 4.6: Idaho Residential - Energy Efficiency Savings and Costs
0.30
_ ID-Res Cum Savings 1.200
L
0 0.25
—ID-Res Total Utility 1.000
Cost ($million)
20.20 �
.� 0.800 4-
cn 0
> 0.15 0.600 0
M
ID cn
z 0.10 0.400
M
M
E 0.05 0.200
t�
0.00 0.000
2026 2027 2030 2035 2040 2045
Figure 4.7: Idaho Commercial - Energy Efficiency Savings and Costs
0.40 0.450
w ID-Com Cum
_ 0.35 Savings (Dth) 0.400
L ID-Com Total Utility
0.30 Cost ($million) 0.350
0_ 0.300
= 0.25 Fr 0
0.250 c
0.20 ,o
c 0.200
CO 0.15 0.150
0.10 0.100
M
0 0.05 0.050
v 0.00 0.000
2026 2027 2030 2035 2040 2045
Avista Corp 2025 Natural Gas IRP 95

Chapter 4: Demand Side Resources
Figure 4.8: Idaho Industrial - Energy Efficiency Savings and Costs
0.030
ID-Ind Cum Savings
(Dth)
0 —ID-Ind Total Utility 0.025
Cost ($million)
0.01 0.020
o
0.015 c
> o
c�
to _
0.010
E 0.005
U
0.00 0.000
2026 2027 2030 2035 2040 2045
Washington and Idaho Energy Efficiency Targets
The methodology for setting EE targets in Washington and Idaho are consistent with the
most immediate two years of the study used to set EE targets. While the current CPA
includes 2025 in its analysis, the next cycle for establishing annual EE targets begins in
2026 and runs through 2027 as a biennial period. Therefore, for the purpose of EE target
setting, cumulative values are used with the first year of the study, 2025, removed. An
additional CPA for Avista's Washington transport customer group was also conducted by
AEG.
Tables 4.1 and 4.2 summarize the 2026 and 2027 targets for Washington and Idaho
respectively based on results of the CPA.
Table 4.1: Washington 2026-2027 Conservation Target by Sector, (Dth)
Class 2026 2027 Total
Residential 19,132 45,189 64,321
Commercial 50,960 106,715 157,675
Industrial 1,649 3,322 4,971
Total 71,741 155,226 226,967
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Chapter 4: Demand Side Resources
Table 4.2: Idaho 2026-2027 Conservation Target by Sector, (Dth)
Class 2026 2027 Total
Residential 13,858 33,833 47,691
Commercial 11,998 25,531 37,528
Industrial 401 818 1,219
Total 26,257 60,182 86,439
As measures are identified by the model for potential savings they are ranked by their
relative contribution. A thorough review process is utilized to provide context; including a
review of assumed ramp rates, availability of the measure, likelihood of adoption within
Avista's service territory and previous experience with programs utilizing the selected
measures. Based on the review and input from the Company and AEG, measures are
either accepted as presented, modified, or removed prior to finalizing the overall targets.
Oregon Energy Efficiency Target:
As technologies and EE policies evolve over the IRP timeline, the Company worked with
the Oregon Public Utility Commission (OPUC), Community Action Agencies, ETO of
Oregon, and other interested parties to adjust offerings to maximize EE savings. AEG
conducted a CPA for Avista's Oregon low-income, and transport customer groups to
enable the Company to better understand the potential when designing programs for
these customers. Energy Trust of Oregon (ETO) conducted a CPA for Avista's residential,
commercial, and interruptible customers which they have served with EE programs since
2017, and interruptible customers starting in 2023. The entire CPA report including the
methodology can be found in Appendix 4.
The Company has exclusively worked with Community Action Agencies (Agencies) to
implement the Avista Oregon Low Income Energy Efficiency (AOLIEE) Program and is
working to expand to other implementing organizations to reach more customers.
Agencies primarily install insulation, air sealing, duct sealing, and provide needed health,
safety, and minor repair for our low-income customers. The results of identified top EE
measures are discussed with the Agencies and ETO to determine the measures that are
readily deployable in the near term, but no measures are removed from the overall
potential. Throughout 2024, Avista engaged the Agencies administering the AOLIEE
Program, the Company's newly formed Equity Advisory Group, ETO, and OPUC staff to
discuss new ways to possibly increase customer participation in the Program.
These engagements provide the basis for the Company's requested modifications to its
AOLIEE Program for 2025, which were approved by the OPUC in Docket No. ADV
1656/Advice No. 24-08-G'. These modifications for the 2025 program year are intended
to expand the reach of the existing program and to prioritize energy burdened customers
within these communities to ensure EE services available are reaching those that need
https://apps.puc.state.or.us/edockets/DocketNoLaVout.asp?DocketiD=24309
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Chapter 4: Demand Side Resources
them most. Avista will continue to work with interested parties including ETO to ramp up
EE programs to reduce the energy burden for low-income customers. Figure 4.9
summarizes the cumulative savings potential results and annual costs for residential
customers as estimated by ETO and residential low-income customers as estimated by
AEG.
Figure 4.9: Oregon Residential Energy Efficiency Savings and Costs
1.20 w-- OR-Res-LI Cum Savings (Dth)
AEG 10.000
0 1.00 OR-Res Cum Savings (Dth) -
o ETO
OR-Res-LI Total Utility Cost 8.000
0.80 ($million) - AEG
OR-Res Total Utility Cost o
0.60
($million) - ETO 6.000
U) =
0.40 4.000
E 0.20
2.000
U
0.00 0.000
2026 2027 2030 2035 2040 2045
Avista offers a carbon reduction program via EE for transport customers and began in
2023 and 2024. The results of top efficiency measures are shared and discussed with
ETO. Measures such as boiler pipe insulation, steam trap replacement, and strategic
energy management2 were available. The Company will continue to work with interested
parties to determine appropriate EE programs for transport customers in 2025. Results
for commercial, industrial and transport customers' cumulative energy savings potential
and annual costs are shown in Figures 4.10 to 4.12.
2 https://www.energytrust.org/industry-agriculture/
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Chapter 4: Demand Side Resources
Figure 4.10: Oregon Commercial Energy Efficiency Savings and Costs
0.60 3.000
OR-Com Cum Savings (Dth) - ETO
=
0 0.50 OR-Com Total Utility Cost ($million) - ETO 2.500
c
0
g 0.40 2.000
.�
cn 0
0.30 1.500
> o
cn =
z 0.20 1.000
c�
0.10 0.500
t�
0.00 0.000
2026 2027 2030 2035 2040 2045
Figure 4.11: Oregon Industrial Energy Efficiency Savings and Costs
0.09 OR-Ind Cum Savings (Dth) - ETO 0.200
0.08 —OR-Ind Total Utility Cost ($million) - ETO 0.180
0
0.07 0.160
0
g 0.06 0.140
N 0.120 c
a� 0.05
0.100 c
•M 0.04
co 0.080
0.03 0.060
0.02 0.040
�j 0.01 0.020
0.00 0.000
2026 2027 2030 2035 2040 2045
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Chapter 4: Demand Side Resources
Figure 4.12: Oregon Transport Energy Efficiency Savings and Costs
0.30
_ OR-Tprt Cum
r Savings (Dth) - AEG 0.020
00.25
r —OR-Tprt Total Utility
° Cost ($million) - AEG
g 0.20 0.015
.� 4-
cn o
M0.15 0.010 .o
co =
0.10
`M 0.005
E 0.05
V
0.00 0.000
2026 2027 2030 2035 2040 2045
As implementor of EE programs for the Company's residential, commercial, and
interruptible customers. ETO provides a full suite of energy efficiency measures3,
including a moderate-income residential program. Avista supports acquiring all cost-
effective potential identified in the CPA and approved by the ETO Board of Directors in
the annual Budget and Action Plan.4 Figure 4.13 shows cumulative potential savings
results by 2045 for all customer classes and studies.
3 https://www.energytrust.org/
4 https://www.energytrust.org/about/reports-financials/budget-action-plan/
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Chapter 4: Demand Side Resources
Figure 4.13: 20-Year Cumulative Savings Potential by Type (Dth)
Ind,
76,351
Com,
Res-LI, 478,056
51 ,164 Tprt,
251,405
Res,
942,354
ETO is continuing to implement a dual fuel heating pilot. The Company continues to
monitor the need for a targeted EE distribution project in the natural gas system which is
discussed further in ;haoter 10 of the IRP. A presentation on this effort and status is
included in Appendix 11 under TAC presentations5.
Demand Response
Electric demand response (DR) programs are well known in electricity markets to provide
capacity at times when wholesale prices are unusually high, when a shortfall of generation
or transmission occurs, or during an emergency grid-operation situation. These types of
programs have not garnered much interest in the natural gas markets. However, some
pilot programs have emerged throughout the U.S. generating industry attention. The
same reasons hold true for considering Natural Gas Demand Response (NGDR)
programs as electric DR programs.
Avista retained AEG, who also performs the electric DR potential assessment, to perform
the NGDR potential assessment study for Avista's Oregon, Washington, and Idaho
service territories.
5 TAC 10
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Chapter 4: Demand Side Resources
Demand Response Potential Assessment Study
AEG's study estimates the potential magnitude, timing, and cost of a variety of NGDR
programs likely available to Avista during winter peak loads over the 20-year planning
horizon (2026-2045). These estimates are then modeled in the IRP to determine the value
and cost effectiveness of each program on Avista's system. Figure 4.14 outlines AEG's
approach to determine potential DR programs in Avista's service territories. The NGDR
behavioral program and DLC Smart thermostat program included in this study require
Advanced Metering Infrastructure (AMI) as an enabling technology for program
performance tracking. Currently Washington is the only state in Avista's service territory
with AMI.
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 NGDR program participation
and provides consideration for NGDR program interactions with EE programs. The study
then compares Avista's market segments to national NGDR programs to identify relevant
NGDR programs for analysis.
Figure 4.14: Program Characterization Process
AMI Select Program Develop
Infrastructure Appropriate Characterization Program
Analysis Programs •Develop participation Hierarchy
-AtvIl is required for •Develop a list of 10 rates. impacts,
cost. •Ensure the potential
participation in appropriate and other key is not double
certain programs programs program parameter counted between
programs
•Determines eligible •Rates.. direct load •In the context of high
populations for rate control. and and low potential
based options economic options cases
This process identified the five NGDR program options shown in Table 4.3.
Curtailable/controllable NGDR programs represent firm, dispatchable and reliable
resources to meet peak-period loads. Overall, DR potential compared to the system peak
is very low, even if all DR programs were implemented, it would only reduce peak demand
by 0.006% in the first year and 0.047% by 2045.
Table 4.3: NGDR Program Options by Market Segment
- Pr Participating Market Segment
. . . .ra Residential Commercial Industrial
. - • .
Curtailable DLC Smart Thermostat X X
Controllable Third Party Contracts X X
DR Behavioral* X X
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Chapter 4: Demand Side Resources
Demand Response Program Descriptions
Direct Load Control Smart Thermostats
Direct Load Control (DLC) Smart Thermostat programs leverage residential and
commercial customer's smart thermostat installation to cycle heating end uses. This
program relies on the customer's WiFi for communications. Typically, DLC programs take
five years to ramp up to maximum participation levels. Customer participation rate
assumptions along with program costs and potential are detailed in Tables 4.4 and 4.5.
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 therm
consumption. Because the program includes a contractual agreement for a specific level
of load reduction, enrolled loads have the potential to be counted toward installed capacity
requirements. Customer participation rate assumptions along with program costs and
potential are detailed in Tables 4.4 and 4.5.
Customers with large process and heating loads that have flexibility in their operations
are attractive candidates for firm curtailment programs. However, 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 NGDR 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.
Behavioral
A behavioral program is a voluntary usage reduction in response to digital behavioral
messaging. These programs typically occur in conjunction with EE home energy report
behavioral programs and communicate the request to customers to reduce usage via text
or email messages. Customer participation rate assumptions along with program costs
and potential are detailed in Tables 4.4 and 4.5.
Natural Gas Demand Response Program Participation
The steady-state participation assumptions rely on AEG's database of existing program
information and insights from market research results representing national "best-
practice" estimates for program participation.
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Chapter 4: Demand Side Resources
Once initiated, NGDR 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. NGDR programs included in the AEG study have ramp rates generally with a
three- to five-year timeframe before reaching a steady state.
Table 4.4 shows the steady-state participation rate assumptions for each NGDR program
option. Eligible customers are calculated by AEG based on market characterization and
equipment end-use saturation. The values shown are considered maximum participation
rates derived from derated usage, like electric DR programs' participation rates.
fable 4.4: NGDR Program Winter Peak Reduction (Dth)
D- Program 040 2045
Behavioral 6.68 10.90 27.81 28.38 29.00 29.66
DLC Smart Thermostats - BYOT 9.71 29.26 98.99 101.55 103.85 104.57
Third Party Contracts 10.00 16.12 20.27 20.49 20.72 20.95
Cost and Potential Assumptions
Each NGDR program used in this evaluation was assigned an average load reduction per
participant per event, an estimated duration of each event, and a total number of event
hours per year. Costs were also assigned to each NGDR program for annual marketing,
recruitment, incentives, program development, and administrative support. These
resulted in potential demand savings and total cost estimates, as shown in Table 4.5, for
each program independently and on a standalone basis. Details on NGDR resource
assumptions can be found in AEG's Natural Gas CPA report, Appendix 4.
Table 4,';' Svctam 0­irnm rnct frnnital and ngRill
D- Programi i i
Behavioral $138,932 $157,490 $362,969 $367,038 $371,401 $376,081
DLC Smart $279,577 $445,076 $690,351 $625,426 $633,010 $636,258
Thermostats - BYOT
Third Party $70,232 $78,717 $84,521 $84,847 $85,191 $85,553
Contracts
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Chapter 4: Demand Side Resources
Building Electrification
State policies in Oregon and Washington may lead customers to electrify their natural gas
space and water heating to reduce greenhouse gas emissions. This IRP includes natural
gas customer choice fuel switching within the demand forecast and offers specific fuel
use electrification as an alternative to natural gas supply as a resource option for both
commercial and residential customers. Industrial customers are not considered in this
analysis due to the variety of processes and needs of the product being produced. Avista
does not have many industrial customers in its territories, with the overall system use of
industrial customers around 1% of system demand. Electrification, if cost effective, must
always be selected for the remaining study horizon. This is built on the assumption of a
customer switching end uses and equipment is unlikely to return to the natural gas system
within the study horizon.
Estimating building electrification costs is not a simple analysis as electrification costs
vary by structure size, efficiency, shell efficiency, and geographical location in respect to
weather. Individual homes at a discrete level and factors may find costs lower than these
estimates, while others may be higher based on home size, location, or complexity of
heating systems. Further, customers may find extrinsic value in natural gas for resilience
benefits and its superior performance compared to electric options. Also, customers may
choose to continue to use natural gas fireplaces, clothes dryers, and stoves, even if
uneconomic. Another concern with fuel switching is affordability, where low-income
customers may not have the ability to pay for an end use conversion creating an equity
issue. A second equity issue concerns if higher income customers leave the system, the
cost per customer for those that remain on the system would go up, resulting in low-
income customers paying a higher cost per customer.
To begin the analysis, the customer type, class and major end use must be separated.
Residential and commercial customers' electrification choices are broken into three
separate categories.
• Space Heat
• Water Heat
• Other (Cooking, clothes dryer)
End Use Efficiency
The estimated values for these sources are used from the CPA studies provided by AEG
and ETO. The second set of assumptions are built around demand variability and certain
sets of temperature groupings. As an example, if a customer's furnace is running
constantly at 65 Heating Degree Days (HDD's), it does not run more if the HDD's increase
with colder temperatures. Climate zone requirements for heating needs differ depending
on geographical location as shown in Figure 4.15.
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Chapter 4: Demand Side Resources
Figure 4.15: Climate Zone IridN-
1/1 IN Dry(B) Moist(A)
Marine(C)
Climate Zone
i
■= 2
■ = 3
Warm-Humid = 4
Below White Line
■ = 5
■ = 6
All of Alaska is in Zone 7 except for 2 ■ = 7
the following boroughs which are in
Zone 8:Bethel,Dellingham,Fairbanks
N.Star,Nome,North Slope,Northwest
Arctic,Southest Fairbanks,Wade Zone 1 includes Hawaii,
Hampton.Yukon-Koyukuk Guam,Puerto Rico.and 1
the Virgin Islands
Figure 4.16 shows the modeled heat pump efficiency for a range of temperatures based
on the amount of energy needed in the form of kWh (Input Btu) and the amount of energy
generated through the heat pump process (Output Btu). While efficiency continues across
all temperatures, the Btu per hour of output shows a declining amount of energy provided
by heat pumps where auxiliary or backup systems are necessary to provide the necessary
energy to fully heat a structure.
6 International Energy Conservation Code (IECC) Climate Regions
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Chapter 4: Demand Side Resources
Figure 4.16: Modeled Heat Pump Efficiency'
60,000 350%
50,000 *WP 300%
I
� 250%
00
40,000
mop
i
r gap 200% a
30,000 I O
pp 150% V
20,000
100%
-Output Btu
10,000 Input in Btu 50%
COP
0 0%
�
N N N M M LO Ln W
Degrees Fahrenheit
Avista combines this estimate with current Avista rates as of November 1, 20248 to
estimate costs of using a heat pump as compared to a 95% efficient natural gas furnace
at different temperatures of operation as shown in Figure 4.17. Although a heat pump can
operate efficiently at low temperatures, the amount of heat output and increased costs
may change the customers' use of heat pumps depending on climate in the region.
Implications of these efficiencies will come into focus when paired with weather regions,
expected energy costs, and conversion costs.
7 ASHP
8 Avista Energy Rates and Tariffs in WA. ID, & OR I Avista
Avista Corp 2025 Natural Gas IRP 107

Chapter 4: Demand Side Resources
Figure 4.17: Electric and Gas Rate Comparison — WA Residential
$4.00
—Avista Electric HP Costs per hour
Residential $3.50
Avista Gas Costs per hour Residential $3.00
a�
�. $2.50 o
$2.00 0
U
$1.50 L
$1.00 =
$0.50
$0.00
-15 -10 -5 0 5 10 15 20 25 30 35 40 45 50 55 60 65
Degrees Fahrenheit
=nergy Demand
A daily demand forecast is important when considering electrification, otherwise the
capacity to serve a peak day is ignored and the system value is not measured
appropriately. This method considers daily temperatures as explained in Chanter . A
demand per customer class and area considers a use per customer energy needed in
therms and utilizes the conversion coefficient to estimate efficiency gains from switching
to electricity. Efficiency is considered as a generic value across equipment and does not
represent ultra-high efficiency units or old lower-efficiency units. These values are then
rolled up into a monthly average to consider conversion efficiency and demand by
planning area. In Figure 4.18, the bars indicate average monthly use per Washington
residential customers in kilowatt hours. These totals include the average customer
monthly demand, and all end uses to illustrate the energy needed from the electric grid
per customer and end use.
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Chapter 4: Demand Side Resources
Figure 4.18: Washington Residential Energy Demand - kWh
2,000 ■Other - Energy Conversion (kWh)
■Space Heat - Energy Conversion (kWh)
Water Heat - Energy Conversion (kWh)
1,500
1,000
Y
I
500
Co r` 00 a) O N M Irr L0 CD r~ 00 a) O N M Iq L0
N N N N M M M M M M M M M M I Iq Iq Iq Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Conversion Costs
Conversion costs can vary widely by study, location, building size, and structure. Avista
used a study by the Rocky Mountain Institute9 to understand estimated costs by area to
help address these ranges. Although the study provides an estimate by major area, no
areas were in Avista`s natural gas service territory. To help account for these wide-
ranging study estimates, Avista considered the generic cost "total to a remodeler". The
cost information from this study is illustrated in Table 4.6. For space heating, we assumed
a 3-ton heat pump would be required on average for a 2,000 square foot house. Sizing
needs estimates for space heat range from a 2.5 ton to a 4 ton for climate zone 4 or 5.10
Incentives and grants are estimated based on known programs such as the Inflation
Reduction Act. These costs are treated as being removed from the overall conversion
cost. Also, these conversion costs are estimated to be recovered over a five-year
timeframe with an interest rate by jurisdiction (OR — 6.1%, WA — 6.58%). Payments are
recovered monthly and in equal amounts like a mortgage payment. The estimated impact
within the study is roughly half of the cost by end use and would be discounted, recovered
by the customer or refundable and removed from the total before the monthly payment is
estimated.
9 The Economics of Electrifying Buildings— December 2022
10 What Size Heat Pump Do I Need (Heat Pump Size Calculator) - PICKHVAC
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Chapter 4: Demand Side Resources
Table 4.6: Estimated Conversion Costs (Dth)" — Real 2026$
EquipmentEnd Use .
Space Heating Air source heat pump, ducted (per ton) $ 1,998
Water Heating heat pump water heater $ 3,528
Cooking electric range $ 2,038
Clothes Dryer electric dryer $ 1,602
Energy Costs
Monthly costs from conversions are included with the energy demand per kWh. The rate
per kWh uses current rates by area and inflates the average of both City of Ashland
electric and Pacific Power customers, Klamath Falls-Medford-Roseburg, by the same
estimated percentage Avista rates would see in meeting 100% clean goals by 2045. La
Grande is served by Oregon Trail Electric and is mainly powered by hydro power from
the Bonneville Power Administration (BPA) and assumes a lower rate increase of 3%
annually after average rate increases in 2026-2028 of 10.8% for power rate and
transmission rate increase of 24%12 for an estimated total of 5% impact based on their
offtake agreement. After 2029, a 3% estimate is broken out as 2% inflation and 1% for
new transmission and distribution projects. The Washington territory estimates include
81% of natural gas customers moving to Avista for their electricity needs and 19% lost to
other public power providers such as Inland Power & Light, Modern Electric, and VERA.
The assumed escalation curves for energy per kWh are included in Figure 4.19. Base
costs are not included as it is assumed a natural gas customer is currently using the local
electric provider. These costs also include estimated generation, distribution and
transmission resources to serve the additional load from the 2025 Avista Electric IRP.
11 Economics of Electrifying Buildings - RMI
12 PR-23-24 Increased investments in infrastructure lead to proposed rate increases
Avista Corp 2025 Natural Gas IRP 110

Chapter 4: Demand Side Resources
Figure 4.19: Electric Rate Assumption by Area by Class (Nominal $)
$0.400
WA Res Rate
$0.350 - WA Corn Rate
La Grande Res Rate
$0.300 La Grande Corn Rate
S. OR Res Rate
$0.250 S. OR Corn Rate
,
$0.200
Y
a� $0.150
$0.100
$0.050
$-
CD r` CO O O N M g LO CD r` CO O O N M Iq LO
N N N N M M M M M M M M M M 'q
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Rate Imaac'
When pairing the cost of energy with the conversion rate in the initial 5 years, a consistent
monthly charge is included, even when energy is not being used in times of low demand,
such as July and August, as illustrated in Figure 4.20. In the warmer months, the cost for
electrification of space heat is from converting the equipment over. In the colder months
when more energy is used, the efficiency of electric end uses help to conserve energy.
Avista Corp 2025 Natural Gas IRP 111

Chapter 4: Demand Side Resources
Figure 4.20: Conversion and Energy Costs - Space Heat WA Residential (2026 $)
$250
Conversion Costs
Energy Costs (kWh)
5 $200
c $150
E
m
_ $100
a�
U
fQ
Q
$50
$0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Each step of the analysis process is summarized below:
1. Estimated demand by area by customer class by end use of natural gas.
2. Conversion efficiency by area and class by temperature.
3. Conversion cost of the building by class.
4. Rate impact by area and class to meet regional carbon reduction goals and includes
additional supply resources, transmission, and distribution cost estimates to provide
the energy.
5. Levelized costs per year to consider conversion costs specific to that year for 5 years
repayment and expected energy costs for the study horizon.
Levciie-ed COaw
The figures below (Figures 4.21 to 4.24) illustrate the final costs used in the model by end
use and class. These costs consider the energy and conversion costs and place into a
net present value monthly payment for each year the full costs over the 20-year forecast
horizon. This helps to capture changing energy costs and IRA incentives expiring after
2032 or before based on government actions.
Avista Corp 2025 Natural Gas IRP 112

Chapter 4: Demand Side Resources
Figure 4.21: Space Heat Levelized Costs by Area for Residential Electrification
$250
La Grande Res - Space Heat
Klamath Falls Res - Space Heat
$200 Medford Res - Space Heat
= Roseburg Res - Space Heat
0
a� $150 WA Res - Space Heat
$100
a�
$50
1
$0
CO r` w M O r N MItt LO (.O r` w M O N MIRt LO
N N N N M M M M M M M M M M IRt qt IqIR* qt "qr
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Fiaure 4.22: Water Heat Levelized Costs by Area for Residential Electrification
$400
La Grande Res - Water Heat
Klamath Falls Res - Water Heat
Medford Res - Water Heat
o $300 Roseburg Res - Water Heat
WA Res - Water Heat
a
� $200
aD
N
—j $100
$0
CO r` CO M O N M Iq LO W r~ CO (n O N CO IqU")
N N N N M M M M M M M M M M qq Iq Iq Iq qq Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Avista Corp 2025 Natural Gas IRP 113

Chapter 4: Demand Side Resources
Figure 4.23: Space Heat Levelized Costs by Area for Commercial Electrification
$500 �La GrandeCom - Space Heat
Klamath Falls Com - Space Heat
Medford Com - Space Heat
r $400 Roseburg Com - Space Heat
WA Com - Space Heat
a $300
.Q
m
$200
J
$100
$0
CD f` CO Q) O N M � LO CD f` 00 M O N M 11 V)
N N N N M M M M M M M M M M � � � � � Itt
O O O O O O O O O O O O O O O O O O CO CO
N N N N N N N N N N N N N N N N N N N N
Figure 4.24: Water Heat Levelized Costs by Area for Commercial Electrification
$500 —La Grande Com - Water Heat
Klamath Falls Com - Water Heat
$400 Medford Com - Water Heat
r Roseburg Com - Water Heat
WA Com - Water Heat
L
a $300
N $200
> r
d
J $100
$0 �r-
(D ti 00 M CDT- N M Iq U) CD r` 00 O O T- N M Iq LO
N N N N M M M M M M M M M M Nt Nt11* Iq qO 10
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 5: Gas Markets and Current Resources
5. Gas Markets and Current Resources
Section Highlights:
• The 20 year levelized price of gas is forecasted to be $4.94 per dekatherm at Henry
Hub and $3.66 per dekatherm at AECO.
• Avista procures 83% of its natural gas from Canada.
• Jackson Prairie can supply Avista's normal winter demand for over 30 days.
• Avista's owned and subscribed assets are optimized to help reduce costs to
customers.
Avista manages natural gas procurement and related activities on a system-wide basis
with several regional supply options available to serve customers. Supply options include
both firm and non-firm natural gas supplies using both firm and interruptible transportation
on six interstate pipelines and natural gas storage. Because Avista's customers span
three states, the diversity of delivery points and demand requirements adds to the options
available to meet customer needs. The utilization of these resources varies depending on
demand and operating conditions. This chapter discusses the available regional
commodity natural gas resources and Avista's procurement plan strategies. The regional
pipeline resource options available to deliver the commodity to customers and the storage
resources available to provide additional supply diversity enhance reliability, flexibility and
favorable price opportunities to meet demand.
Natural Gas Commodity Resources
Supply Basins
The Northwest continues to enjoy a low-cost commodity environment with abundant
supply availability, especially when compared to other regions across the globe. This is
primarily due to the production in the Northeast and Southern United States. This supply
is serving an increasing amount of demand in heavily populated areas in the middle and
eastern portions of Canada and the U.S. This dynamic displaces supplies previously
delivered from the Western Canadian Sedimentary Basis (WCSB).
Current price forecasts show a long-term regional price advantage for the Western
Canada and Rockies natural gas basins as the need for natural gas in the east diminishes.
Higher Canadian production paired with limited options for flowing natural gas into
demand areas has created a generally discounted commodity in the Northwest when
compared to the Henry Hub. Access to these abundant supplies of natural gas and to
major markets across the continent has also led to the construction of multiple LNG
plants. These LNG plants will be a large addition to North American demand and are on
track to more than double by 2028.1. A Canadian project (LNG Canada), located in Kitimat
North America's LNG export capacity is on track to more than double by 2028 - U.S. Energy Information
Administration (EIA)
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Chapter 5: Gas Markets and Current Resources
B.C. represents one of the largest investments in Canadian history and is expected to
export up to 14 million tonnes of LNG per year, or 2 Bcf per day, by 2025. Another
Canadian project (Woodfibre LNG), located in Squamish, B.C., plans to come online in
2027, removing potentially 0.3 Bcf from supply available to the Pacific Northwest. It is
stated to be the first net zero LNG facility in the world. Due to the limited infrastructure in
the Pacific Northwest, the large increase of natural gas demand by either of these facilities
moving forward could cause pressure on commodity prices.
Exports to Mexico continue to impact U.S. natural gas demand forecasts. In 2013, Mexico
reformed its energy sector allowing new market participants, innovative technologies, and
foreign investments. Additionally, this market reformation opened new opportunities for
natural gas export to Mexico. Since these market changes, Mexican imports reached as
much as 7 Bcf per day on average as compared to less than 2 Bcf per day prior to these
changes.
Recent changes to tariffs with Canada and Mexico may impact regional natural gas
prices. The modeling work for this IRP was substantially completed prior to the tariff
proposals that are still being developed. These costs will be analyzed in the 2027 IRP
when they should be finalized.
Reqional Market HubF
There are numerous regional market hubs in the Pacific Northwest where natural gas is
traded extending from the two primary basins. These regional hubs are typically located
at pipeline interconnects. Avista's service area and pipeline rights are near most of the
Pacific Northwest regional market hubs enabling flexible access to geographically diverse
supply points. These supply points include:
• AECO — The AECO-C/Nova Inventory Transfer market center located in Alberta is
a major connection region to long-distance transportation systems taking natural
gas to points throughout Canada and the United States. Alberta is the primary
Canadian exporter of natural gas to the U.S. and historically produces 90% of
Canada's natural gas.
• Rockies — This pricing point represents several locations on the southern end of
the NWP system in the Rocky Mountain region. The system draws on Rocky
Mountain natural gas-producing areas clustered in areas of Colorado, Utah, New
Mexico, and Wyoming.
• Sumas/Huntingdon — The Sumas, Washington pricing point is on the
U.S./Canadian border where the northern end of the NWP system connects with
Enbridge's Westcoast Pipeline and predominantly markets Canadian natural gas
from Northern British Columbia.
• Malin — This pricing point is at Malin, Oregon, on the California/Oregon border
where TransCanada's Gas Transmission Northwest (GTN) and Pacific Gas &
Electric Company connect.
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Chapter 5: Gas Markets and Current Resources
• Station 2 — Located at the center of the Enbridge's Westcoast Pipeline system
connecting to northern British Columbia natural gas production.
• Stanfield — Located near the Washington/Oregon border at the intersection of the
NWP and GTN pipelines.
• Kingsgate — Located at the U.S./Canadian (Idaho) border where the GTN pipeline
connects with the TransCanada Foothills pipeline.
Natural gas pricing is often compared to the Henry Hub price given the ability to transport
natural gas across North America. Henry Hub, located in Louisiana, is the primary natural
gas pricing point in the U.S. and is the trading point used in the New York Mercantile
Exchange (NYMEX)futures contracts. Figure 5.1 shows historic annual natural gas prices
since 2012 at AECO, Rockies, Malin, Stanfield and Sumas. Hub prices have changed in
recent years due to shifts in flows of natural gas specifically coming from Western
Canada.
Figure 5.1: Average Annual Index Prices
$9
AECO - Rockies
o $8 Mali n Stanfield
$7 Sumas
a
$6
a�
M $5
c-
L
CD
�.,
a
$4
ca $3 /
Q
$2
$1
$-
N M Iq LO CO r~ CO M O T_ N M Iq
T_ T_ T_ T_ T_ T_ T_ T_ N N N N N
O O O O O O O O O O O O O
N N N N N N N N N N N N N
Northwest regional natural gas prices typically move together; however, the basis
differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints, and the ability to shift supplies to
higher-priced delivery points in the U.S. or Canada. By monitoring these price shifts,
Avista can often purchase at the lowest-priced trading hubs on a given day, subject to
operational and contractual constraints.
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Chapter 5: Gas Markets and Current Resources
Liquidity is generally sufficient in the day-markets at most Northwest supply points. AECO
continues to be the most liquid supply point, especially for longer-term transactions.
Sumas has historically been the least liquid of the four major regional supply points
(AECO, Rockies, Sumas, and Malin). This relative illiquidity contributes to generally
higher comparative prices in the high demand winter months.
Avista procures natural gas with contracts. Contract specifics vary from transaction-to-
transaction, and many of those terms or conditions affect commodity pricing. Some of the
terms and conditions include:
• Firm versus Non-Firm: Most term contracts specify the supply is firm except for
force majeure conditions. In the case of non-firm supplies, the standard provision
is that the supply can be cut for reasons other than force majeure conditions.
• Fixed versus Floating Pricing: The agreed-upon price for the delivered natural
gas may be fixed or based on a daily or monthly index.
• Physical versus Financial: Certain counterparties, such as investment banking
institutions, may not trade physical natural gas, but are still active in the natural
gas markets. Rather than managing physical supplies, those counterparties
choose to transact financially rather than physically. Financial transactions provide
another way for Avista to financially hedge prices.
• Load Factor/Variable Take: Some contracts have fixed reservation charges
assessed during each of the winter months, while others have minimum daily or
monthly take requirements. Depending on the specific provisions, the resulting
commodity price will contain a discount or premium compared to standard terms.
• Liquidated Damages: Most contracts contain provisions for symmetrical penalties
for failure to take or supply natural gas.
For this IRP, Avista assumes natural gas purchases under a firm, physical, fixed-price
contract, regardless of contract execution date and type of contract. Avista pursues a
variety of contractual terms and conditions to capture the most value for customers.
Avista`s natural gas buyers actively assess the most cost-effective way to meet customer
demand and optimize unutilized resources.
Natural Gas Price Forecasts
Natural gas prices play an integral role in the development of the IRP. It is the most
significant variable in determining the cost-effectiveness of energy efficiency measures
and of procuring new resources. The natural gas price outlook has changed dramatically
in recent years in response to several influential events and trends affecting the industry,
including improved drilling methods and technology used in oil and natural gas
production, increasing exports to Mexico, and ever-growing LNG exports as discussed
above. These factors, in addition to more stringent renewable energy standards and
increased need for natural gas-fired generation to back up such resources, are
Avista Corp 2025 Natural Gas IRP 118

Chapter 5: Gas Markets and Current Resources
contributing to the rapidly changing natural gas market environment. The uncertainty in
predicting future events and trends requires modeling a range of forecasts.
Many additional factors influence natural gas pricing and volatility, such as regional supply
and demand issues, weather conditions, storage levels, natural gas-fired generation,
infrastructure disruptions, and infrastructure additions, such as new pipelines and LNG
terminals. Renewable fuels used in place of fossil natural gas and demand loss from
policy implications will alter the variables affecting future natural gas prices. Estimates of
these supply resource changes vary between studies as the study date and ultimately
drive the primary differences between sources in pricing expectations.
Although Avista closely monitors these factors, we cannot accurately predict future prices
across the 20-year horizon of this IRP. As a result, several price forecasts from credible
industry experts were used in developing the price forecasts considered in this IRP.
Figure 5.2 depicts the annual average prices of these combined forecasts in nominal
dollars and includes the expected price resulting from a blending technique.
Figure 5.2: Henry Hub Forecasted Price Study Forecasts (Nominal $/Dekatherm)
$10
Actuals Nymex ! EIA/AEO
$9 -Consultant 1 Consultant 2 Expected Case
$8
$7
r $6
$5
a $4
60
$3
$2
$1
$0
00 O N ­t CD 00 O N qq CD 00 O N q�t CD 00 O N qct
O T­ T­ T­ T­ N N N N N CO CO CO M CO Iq q�t qt*
O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N
Expected prices at Henry Hub were derived through a blend of forecasts from four
sources, including the NYMEX forward strip on November 11, 2025, and the Energy
Information Administration's (EIA) 2023 Annual Energy Outlook (AEO), and the
fundamentals based forecasts from two reputable energy market consultants. Combining
multiple forecasts improves the accuracy of models because the aggregate market
discerns more information than any single entity or model. The weightings applied to each
Avista Corp 2025 Natural Gas IRP 119

Chapter 5: Gas Markets and Current Resources
source vary throughout the 20-year forecasting horizon. Due to the high volume of market
transactions, expected prices align completely with those of the NYMEX forward strip in
the first year. From 2027 through 2029, market activity and speculation on the NYMEX
deteriorate significantly, so forecasts from the other three sources, proportionally, are
applied by incrementally more weighting. By the year 2030, and through the end of the
forecasting horizon, the expected price is the result of an equally weighted blend of
forecasts from the ETA's AEO and Avista's two market consultants. The specific
weightings applied are described in Table 5.1 and the resulting annual average expected
price at Henry Hub is depicted in Figure 5.3. On a levelized basis the real Henry Hub
price is $4.94 per dth between 2026 and 2045.
Table 5.1 : Price Blend Methodology
MethodologyYears Price Blend
2026 forward price only
2027 75% forward price/25% average consultant forecasts
2028 50% forward price/50% average consultant forecasts
2029 25% forward price/75% average consultant forecasts
2030 - 2045 100% average consultant forecasts
Figure 5.3: Expected Price with Allocated Price Forecast
$12 100%
$10
75%
m $8
a � � a�
$6 — 50% 00
c
o
$4 0
0 25%
Z $2
$- 0%
Wf- 00MO NMIqU') WtiCOMO NMIqIn
N N N N M M M M M M M M M M V V V V V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
6L Expected Case EIA/AEO Consultant 1
Consultant 2 Nymex
To accommodate for the likelihood, the expected prices at Henry Hub do not perfectly
reflect future natural gas prices and to help measure price risk in resource planning, a
Avista Corp 2025 Natural Gas IRP 120

Chapter 5: Gas Markets and Current Resources
stochastic analysis of 500 possible futures was modeled based on the expected price
forecast. Each future contains unique monthly price movements throughout the 20-year
forecasting horizon. With the assistance of the TAC, Avista selected the 95t" and 25tn
highest prices in each month from the stochastic results to determine high and low-price
curves, respectively. The high, expected, and low-price curves in nominal dollars are
illustrated in Figure 5.4.
Figure 5.4: Henry Hub Prices for Low/ Expected/ High Price Scenarios
$16
—Min Mean —Max
$14
$12
0
$10
a
$8
E
$6
o y�
Z $4
$2
$_
CD f�- CO M O N MIRt LO W r- 00 M O N M .4 LO
N N N N M M M M M M M M M M q 'q 'qqtt q1
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Henry Hub is in southeastern Louisiana, near the Gulf of Mexico. It is recognized as the
most important pricing point in the U.S. due to its proximity to large production basins for
U.S. natural gas production and the sheer volume traded in the daily, spot, and forward
markets via the NYMEX futures contracts. Consequently, prices at other trading points
tend to follow Henry Hub with a positive or negative basis differential. Of the two market
consultants Avista uses, only one forecasts basis pricing at the gas hubs modeled
throughout the 20-year horizon as a percentage of basis to Henry Hub for all modeled
basins as discussed above. This percentage basis is an important consideration, in terms
of stochastics, as when Henry Hub pricing gets low enough, simply using a differential
can create negative prices at local hubs and is not a reasonable assumption.
The natural gas hubs at Sumas, AECO, and the Rockies (and other secondary regional
market hubs) determine Avista's costs. Prices at these points typically trade at a discount
in the summer, or negative basis differential, and flip to a higher cost as compared to the
Henry Hub in the winter. This is based on supply constraints in the major demand areas
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Chapter 5: Gas Markets and Current Resources
such as Seattle, WA and Portland, OR. Figure 5.5 shows the resulting regional prices
compared to Henry Hub and Figure 5.6 shows the resulting price distribution for AECO
for the 500 future simulations. Table 5.2 shows the annual natural gas price by basin in
nominal dollars.
rigure 5.5: Regional and Henry Hub Pricing Comparison
$10
—Henry Hub —AECO Malin
$8 Stanfield - Sumas
o �
a� $6
CL
$4
E
0
z
$2
CO r` 00 C� O N MIrr LO (.0 ti W O O N M � U")
N N N N M M M M M M M M M M � � � � � �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 5.6: AECO - $ per Dth (500 Draws)
120
Average: 4.01
100 Min: 0.68
Max: 37.39
80 5th %: 1.93
95th %: 7.75
60 Std. Dev.: 1.98
a�
L
U- 40
20
0 �
T- 00 LO N O (0 M O 1` � r 00 LO N M W CII O
00 O M (P 00 T- R* h 0 N 0 1'- O M LO c0 1*
N M M M M -4 -4 -4 .4 6 6 6 6 6 6 6 r-- ti
ER EA E91 691 69} ER Ef} 81} 81} EF} Ql! bR (ft EA V), Ef} ER Ef}
- _
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. . . . . . . . . . . . . . . . . .
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61) 61). 61). EFy E9 8R 8I} 81} 61} 61} 69} 69} 6R 6R 69 ER 8R ER
— — —
Avista Corp 2025 Natural Gas IRP 122

Chapter 5: Gas Markets and Current Resources
Table 5.2 : Annual Natural Gas Price by Basin (Nominal $)
Years Henry • AECO Rockies Sumas Malin Stanfield
2026 $3.57 $2.64 $3.44 $3.35 $3.50 $3.27
2027 $3.77 $2.85 $3.66 $3.45 $3.62 $3.38
2028 $3.92 $2.90 $3.75 $3.47 $3.58 $3.39
2029 $4.01 $2.94 $3.77 $3.46 $3.61 $3.37
2030 $4.12 $3.01 $3.91 $3.60 $3.77 $3.63
2031 $4.25 $3.10 $4.06 $3.75 $3.85 $3.71
2032 $4.44 $3.27 $4.24 $3.92 $4.05 $3.88
2033 $4.74 $3.55 $4.49 $4.21 $4.35 $4.16
2034 $5.00 $3.72 $4.73 $4.42 $4.52 $4.33
2035 $5.14 $3.87 $4.86 $4.52 $4.55 $4.36
2036 $5.30 $4.04 $5.01 $4.63 $4.59 $4.47
2037 $5.54 $4.15 $5.18 $4.75 $4.80 $4.64
2038 $5.84 $4.35 $5.38 $4.93 $4.93 $4.80
2039 $6.04 $4.47 $5.51 $5.05 $5.06 $4.93
2040 $6.50 $4.82 $5.92 $5.43 $5.46 $5.28
2041 $6.72 $4.96 $6.03 $5.55 $5.45 $5.38
2042 $6.99 $5.14 $6.23 $5.80 $5.83 $5.64
2043 $7.16 $5.26 $6.33 $5.93 $5.90 $5.76
2044 $7.54 $5.50 $6.62 $6.22 $6.20 $6.05
2045 $7.83 $5.72 $6.83 $6.46 $6.45 $6.22
Levelized $4.94 $3.66 $4.61 $4.29 $4.37 $4.20
Transportation Resources
Although proximity to liquid market hubs is important from a cost perspective, supplies
are only as reliable as the pipeline transportation from the hubs to Avista's service
territories. Capturing favorable price differentials and mitigating price and operational risk
can also be realized by holding multiple pipeline transportation options. Avista contracts
for enough diversified firm pipeline capacity from various receipt and delivery points
(including storage facilities), to ensure firm deliveries will meet peak day demand. This
combination of firm transportation rights to Avista's service territory, storage facilities and
access to liquid supply basins ensure peak supplies are available to serve core
customers. The regional map, from the Northwest Gas Association (NWGA), shows the
relative capacity of the pipelines and storage capacity (Figure 5.7).
Avista Corp 2025 Natural Gas IRP 123

Chapter 5: Gas Markets and Current Resources
Figure 5.7: Regional Pipeline and Storage Capacity
2060
155
153 Sum
1753
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1 2850 —Fortis BC System
Enbridge BC Pipeline
/ TC GTN
Starr Road —TC Energy rgy NGT L
i65 —Williams Northwest Pipeline
Palouse
1196 305/ 69 Other Pipelines
_ Underground Storage
656 5So b * Jackson Prairie
Mist
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Stanfield A, Nampa
706 60 Newport
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A Portland
65 A Tilbury
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t[/ ♦� 1500
The major pipelines servicing the region include:
• Williams - Northwest Pipeline (NWP):
A natural gas transmission pipeline serving the Pacific Northwest moving natural
gas from the U.S./Canadian border in Washington and from the U.S. Rocky
Mountain region.
• TransCanada Gas Transmission Northwest (GTN): A natural gas transmission
pipeline originating at Kingsgate, Idaho, (Canadian/U.S. border) and terminating
at the California/Oregon border close to Malin, Oregon.
• TransCanada Alberta System (NGTL): This natural gas gathering and transmission
pipeline in Alberta, Canada, delivers natural gas into the TransCanada Foothills
pipeline at the Alberta/British Columbia border.
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• TransCanada Foothills System: This natural gas transmission pipeline delivers
natural gas between the Alberta - British Columbia border and the Canadian/U.S.
border at Kingsgate, Idaho.
• TransCanada Tuscarora Gas Transmission: This natural gas transmission pipeline
originates at Malin, Oregon, and terminates at Wadsworth, Nevada.
• Enbridge -Westcoast Pipeline: This natural gas transmission pipeline originates at
Fort Nelson, British Columbia, and terminates at the Canadian/U.S. border at
Huntington, British Columbia/Sumas, Washington.
• El Paso Natural Gas - Ruby pipeline: This natural gas transmission pipeline brings
supplies from the Rocky Mountain region of the U.S. to interconnections near
Malin, Oregon.
Avista has contracts with all the above pipelines (except for the Ruby Pipeline) for firm
transportation to serve customers. Table 5.3 details the firm transportation/resource
services contracted by Avista. These contracts are of different vintages with different
expiration dates; however, all have the right to be renewed by Avista. This gives Avista,
and its customers, the available capacity to meet existing demand now and in the future.
Table 5.3: Firm Transportation Resources Contracted (Dth/Day)
Avista North Avista South
TransportationFirm
NWP TF-1 157,869 157,869 42,699 42,699
GTN T-1 100,605 75,782 42,260 20,640
NWP TF-2 91,200 2,623
Total 349,674 233,651 87,582 63,339
Jackson Prairie 346,667 54,623
*Represents original contract amounts after releases expire
Avista defines two categories of interstate pipeline capacity. Direct-connect pipelines
deliver supplies directly to Avista's local distribution system from production areas,
storage facilities, or interconnections with other pipelines. Upstream pipelines deliver
natural gas to the direct-connect pipelines from remote production areas, market centers
and out-of-area storage facilities. Firm Storage Resources - Max Deliverability is
specifically tied to Avista's withdrawal rights at the Jackson Prairie storage facility and is
based on the Company's one third ownership rights. This number only indicates how
much Avista can withdraw from the facility, as transport on NWP is needed to move it
Avista Corp 2025 Natural Gas IRP 125

Chapter 5: Gas Markets and Current Resources
from the facility itself. Figure 5.8 illustrates the direct-connect pipeline network relative to
Avista's supply sources and service territories.2
Figure 5.8: Direct-Connect Pipelines
AECo
Station 2 Kingsgate
Sumas
•
•
•
•
•
JP
Storage Washington 4• Idaho
•
•
Stanfield
•
•
•
LaGrande ••
Roseburg& Klamath •
Medford Falls
• Rockies
• NWP
Malin GTN ■■■■■■
Supply-side resource decisions focus on where to purchase natural gas and how to
deliver it to customers. Each LDC has distinct service territories and geography relative
to supply sources and pipeline infrastructure. Solutions delivering supply to service
territories among regional LDCs are similar but are rarely identical.
The NWP system is effectively a fully contracted pipeline. Except for La Grande, OR,
Avista's service territories lie at the end of NWP pipeline laterals. The Spokane, Coeur
d'Alene, and Lewiston laterals serve Washington and Idaho load, and the Grants Pass
lateral serves Roseburg and Medford. Capacity expansions of these laterals would be
lengthy and costly endeavors resulting in Avista customers likely bearing most of the
incremental costs.
The GTN system, also fully contracted, runs from the Kingsgate trading point on the
Idaho-Canadian border to Malin on the Oregon-California border. This pipeline runs
directly through or near most of Avista's service territories. Mileage based rates provide
an attractive option for securing incremental resource needs.
Peak day planning aside, both pipelines provide an array of options to flexibly manage
daily operations. The NWP and GTN pipelines directly serve Avista's two largest service
2 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a
natural gas transmission pipeline originating at Malin, Oregon, to service a small number of Oregon
customers near the southern border of the state.
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Chapter 5: Gas Markets and Current Resources
territories, providing diversification and risk mitigation with respect to supply source, price
and reliability. NWP provides direct access to Rockies and British Columbia supplies and
facilitates optionality for storage facility management. The Stanfield interconnect of the
two lines is also geographically well situated to serve Avista's service territories.
The rates used in the planning model start with filed rates currently in effect (See
Appendix 5 — Current Transportation/Storage Rates and Assumptions). Forecasting
future pipeline rates is challenging. Assumptions for future rate changes are the result of
market information on comparable pipeline projects, prior rate case experience, and
informal discussions with regional pipeline owners. Pipelines will file new tariffs with
FERC to recover costs at rates equal to their cost of service.
NWP and GTN also offer interruptible transportation services. Interruptible transportation
is subject to curtailment when pipeline capacity constraints limit the amount of natural gas
that may be moved. Although the commodity cost per dekatherm transported is generally
the same as firm transportation, there are no demand or reservation charges in these
interruptible transportation contracts. Avista does not rely on interruptible capacity to meet
peak day demand requirements.
Avista's transportation acquisition strategy is to contract for firm transportation to serve
customers on a peak day in the planning horizon. Since contracts for pipeline capacity
are often lengthy and customer demand needs can vary over time, determining the
appropriate level of firm transportation is a complex analysis. The analysis includes the
projected number of firm customers and their expected annual and peak day demand,
opportunities for future pipeline or storage expansions, and relative costs between
pipelines and upstream supplies. This analysis is done on a semi-annual basis and
through the IRP. Active management of underutilized transportation capacity either
through the capacity release market or engaging in optimization transactions to recover
some transportation costs, keeps Avista's portfolio flexible while minimizing costs to
customers. Timely analysis is also important to maintain an appropriate time cushion to
allow for required lead times should the need for securing new capacity arise (See
1aN«1 for a description of the management of underutilized pipeline resources).
Avista manages existing resources through optimization to mitigate the costs incurred by
customers until the resource is required to meet demand. The recovery of transportation
costs is often market based with rules governed by FERC. The management of long- and
short-term resources ensures the goal of meeting firm customer demand in a reliable and
cost-effective manner. Unutilized resources like supply, transportation, storage, and
capacity can be combined to create products that capture more value than the individual
pieces. Avista has structured long-term arrangements with other utilities allowing
available resource utilization and provides products that no individual component can
satisfy. These products provide more cost recovery of the fixed charges incurred for the
resources. Another strategy to mitigate transportation costs is to participate in the daily
Avista Corp 2025 Natural Gas IRP 127

Chapter 5: Gas Markets and Current Resources
market to assess if any unutilized capacity has value. Avista seeks daily opportunities to
purchase natural gas, transport it on existing unutilized capacity, and sell it into a higher
priced market to capture the cost of the natural gas purchased and recover some pipeline
charges. The recovery is market dependent and may or may not recover all pipeline costs
but mitigates pipeline costs to customers.
Storage Kesources
Storage is a valuable strategic resource enabling Avista to manage seasonal and varied
demand profiles. Storage benefits include:
• Flexibility to serve peak period needs;
• Access to typically lower cost off-peak supplies;
• Reduced need for higher cost annual firm transportation;
• Improved utilization of existing firm transportation via off-season storage injections;
and
• Additional supply point diversity.
While there are several storage facilities available in the region, Avista's existing storage
resources consist solely of ownership and leasehold rights at the Jackson Prairie Storage
facility. Avista optimizes storage as part of its asset management program. This helps to
ensure a controlled cost mechanism is in place to manage the large supply found within
the storage facility. An example of this storage optimization is selling today at a cash price
and buying a forward month contract or selling between different forward months. Since
forward months have risks or premiums built into the price the result is Avista locking in
the spread. Storage optimization takes place while maintaining the peak day deliverability,
at a not to exceed level, to plan for this cost-effective resource to serve customer needs.
All benefits of optimization directly help to reduce the costs to our customers.
ackson Prairie Storage (JP)
Avista is one-third owner, with Williams (NWP)3 and Puget Sound Energy (PSE), of the
Jackson Prairie Storage Project for the benefit of its customers in all three states. Jackson
Prairie Storage is an underground reservoir facility located near Chehalis, Washington
approximately 30 miles south of Olympia, Washington. The total working natural gas
capacity of the facility is approximately 25 Bcf. Avista's current share of this capacity for
customers is approximately 8.5 Bcf and includes 398,667 Dth of daily deliverability rights.
Besides ownership rights, Avista leased an additional 95,565 Dth of Jackson Prairie
capacity with 2,623 Dth of deliverability from NWP to serve Oregon customers.
3 Northwest Pipe
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Chapter 5: Gas Markets and Current Resources
Avista's Natural Gas Procurement Plan
Avista's foundational purpose/goal of the natural gas procurement plan is to provide a
diversified portfolio of reliable supply while managing cost volatility. Avista manages the
procurement plan by layering in purchases over time based on expected demand per
month. Avista does not measure the success of this plan based on a certain cost or loss
risk, rather it is considered successful when Avista has secured firm load at a reasonable
price while addressing risk inherent within these markets. The measurable objectives
monitored toward this goal include a daily financial position of the overall portfolio,
tracking of all new and previously transacted hedges, and the tracking of remaining
hedges yet to be purchased based on a percentage of forecasted load as specified in the
procurement plan.
No company can accurately predict future natural gas prices; however, market conditions
and experience help shape Avista's overall approach to natural gas procurement. Avista's
procurement plan seeks to acquire natural gas supplies while reducing exposure to short-
term price and load volatility. This is done by utilizing a combination of strategies to reduce
the impacts of changing natural gas prices in a volatile market. A portion of hedges will
be focused on the concentration risk of fixed-price natural gas purchases by utilizing
hedge windows, and another portion of hedges will target reducing risk in a volatile market
by utilizing risk responsive methods. This allows Avista to set a risk level to help reduce
exposure to events outside of the Company's control, such as the Energy Crisis in the
early 2000s, the Enbridge pipeline rupture in 2018, or most recently the COVID-19
pandemic and subsequent oil price collapse.
Hedge transactions may be executed for a period of one month through thirty-six months
prior to delivery period and are for the Local Distribution Customer (LDC) only. Due to
Avista's geographic location, transactions may be executed at different supply basins to
reduce overall portfolio risk. This procurement plan is disciplined, yet flexible, allowing for
modifications due to changing market conditions, demand, resource availability, or other
opportunities. Should economic or other factors warrant, any material changes are
communicated to senior management and Commission Staff.
In addition to hedges, the Company's procurement plan includes storage utilization and
daily/monthly index purchases. It is diversified through time, location, and counterparty in
accordance with Risk Management credit terms.
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Chapter 5: Gas Markets and Current Resources
Market-Related Risks and Risk Management
There are several types of risk and approaches to risk management. The 2025 IRP
focuses on three areas of risk: 1) the financial risk of the cost of natural gas system fuel
options to supply customers will be unreasonably high or volatile, 2) emissions
compliance cost and options in Oregon and Washington and, 3) the physical risk that
there may not be enough natural gas system resources (either transportation capacity or
the commodity) to serve customers.
Avista's Risk Management Policy describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses issues
related to management oversight and responsibilities, internal reporting requirements,
documentation and transaction tracking, and credit risk.
Two internal organizations assist in the establishment, reporting, and review of Avista's
business activities as they relate to management of natural gas business risks:
• The Risk Management Committee includes corporate officers and senior-level
management. The committee establishes the Risk Management Policy and
monitors compliance. They receive regular reports on natural gas activity and meet
regularly to discuss market conditions, hedging activity and other natural gas-
related matters.
• The Strategic Oversight Group coordinates natural gas matters among internal
natural gas-related participants and serves as a reference/sounding board for
strategic decisions, including hedges, made by the Natural Gas Supply
department. Members include representatives from the Gas Supply, Accounting,
Regulatory, Credit, Power Resources, and Risk Management departments. While
the Natural Gas Supply department is responsible for implementing hedge
transactions, the Strategic Oversight Group provides input and advice.
Strategic Initiatives
Strategic Initiatives are generally defined as the means by which a vision is translated
into practice. These initiatives are a group of projects and programs that are outside of
the organization's daily operational activities and help an organization achieve a targeted
performance.
The two primary roles of the Energy Resources Department (including Natural Gas
Supply) are now two-fold:
• Serve Load — Assure adequate and reliable energy supplies for Avista's natural
gas customers.
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Chapter 5: Gas Markets and Current Resources
• Manage Resources — Exercise prudent stewardship of Avista's energy supply
facilities and related Company resources.
A thorough review and filing is done annually by Avista for a retrospective hedging report
submitted to each requesting commission. This report provides a detailed summary of
current plan elements and performance over the past year and is filed along with a tariff
revision filing of the annual PGA rates.
Resource Utilization
Avista plans to meet firm customer demand requirements in a cost-effective manner. This
goal encompasses a range of activities from meeting peak day requirements in the winter
to acting as a responsible steward of resources during periods of lower resource
utilization. As the analysis presented in this IRP indicates, Avista has ample transportation
resources to meet highly variable energy demand under multiple scenarios, including
peak weather events.
Avista acquired most of its upstream pipeline capacity during the deregulation, or
unbundling, of the natural gas industry. Pipelines were required to allocate capacity and
costs to their existing customers as they transitioned to transportation only service
providers. The FERC allowed a rate structure for pipelines to recover costs through a
Straight Fixed Variable rate design. This rate structure is based on a higher reservation
charge to cover pipeline costs whether natural gas is transported or not, and a much
smaller variable charge which is incurred only when natural gas is transported. An
additional fuel charge is assessed to fuel the compressors required to move the natural
gas to customers. Avista maintains enough firm capacity to meet peak day requirements
under the PRS in this IRP. This requires pipeline capacity contracts at levels more than
the average and above minimum load requirements. Given this load profile and the
Straight Fixed Variable rate design, Avista incurs ongoing pipeline costs during non-peak
periods.
Avista chooses to have an active, hands-on management of resources to mitigate
upstream pipeline and commodity costs for customers when the capacity is not utilized
for system load requirements. This active management simultaneously deploys multiple
long- and short-term strategies to meet firm demand requirements in a cost-effective
manner. The resource strategies addressed are:
• Emissions compliance;
• Pipeline contract terms;
• Pipeline capacity;
• Storage;
• Commodity and transport optimization; and
• Combination of available resources.
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Chapter 5: Gas Markets and Current Resources
Pipeline Contract Terms
Some pipeline costs are incurred whether the capacity is utilized or not. Winter demand
must be satisfied, and peak days must be met. Ideally, capacity could be contracted from
pipelines only for the time and days needed. Unfortunately, this is not how pipelines are
contracted or built. Long-term agreements at fixed volumes are usually required for
building or acquiring firm transport. This assures the pipeline of long-term, reasonable
cost recovery.
Avista has negotiated and contracted for several seasonal transportation agreements.
These agreements allow volumes to increase during the demand intensive winter months
and decrease over the lower demand summer period. This is a preferred contracting
strategy because it reduces costs when demand is low. Avista refers to this as a front-
line strategy because it attempts to mitigate costs prior to contracting the resource. Not
all pipelines offer this option. Avista seeks this type of arrangement where available.
Avista currently has some seasonal transportation contracts on TransCanada GTN in
addition to contracted volumes of TF2 on NWP. This is a storage specific contract and
matches up the withdrawal capacity at Jackson Prairie with pipeline transport to Avista's
service territories. TF2 is a firm service and allows for contracting a daily amount of
transportation for a specified number of days rather than a daily amount on an annual
basis as is usually required. For example, one of the TF2 agreements allows Avista to
transport 91,200 Dth/day for 31 days. This is a more cost-effective strategy for storage
transport than contracting for an annual amount. Through NWP's tariff, Avista maintains
an option to increase or decrease the number of days this transportation option is
available. More days increases transport costs, so balancing storage, transport, and
demand is important to blend of lower cost and reliability.
Pipeline Capacity
After contracting for pipeline capacity, its management and utilization determine the
actual costs. The worst-case economic scenario is to do nothing and simply incur the
costs associated with this transport contract over the long-term to meet current and future
peak demand requirements. Avista develops strategies to ensure this does not happen
on a regular basis if possible.
Capacity Release
Through the pipeline unbundling of transportation, the FERC establishes rules and
procedures to ensure a fair market developed to manage pipeline capacity as a
commodity. This evolved into the capacity release market, and it is governed by FERC
regulations through individual pipelines. The pipelines implement the FERC's posting
requirements to ensure a transparent and fair market is maintained for the pipeline
capacity. All capacity releases are posted on the pipeline Bulletin Boards and, depending
on the terms, may be subject to bidding in an open market. This provides the transparency
sought by the FERC in establishing the release requirements. Avista utilizes the capacity
release market to manage both long-term and short-term transportation capacity needs.
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Chapter 5: Gas Markets and Current Resources
For capacity under contract that may exceed current demand, Avista seeks other parties
that may need it and arranges for capacity releases to transfer rights, obligations, and
costs. This shifts all or a portion of the costs away from Avista's customers to a third party
until it is needed to meet customer demand.
Many variables determine the value of natural gas transportation. Certain pipeline paths
are more valuable, and this can vary by year, season, month, and day. The term, volume
and conditions present also contribute to the value recoverable through a capacity
release. For example, a release of winter capacity to a third party may allow for full cost
recovery; while a release for the same period that allows Avista to recall capacity for up
to 10 days during the winter may not be as valuable to the third party, but of high value to
the Company. Avista may be willing to offer a discount to retain the recall rights during
high demand periods. This turns a seasonal-for-annual cost into a peak-only cost. Market
terms and conditions are negotiated to determine the value or discount required by both
parties.
Avista has several long-term releases, some extending multiple years, providing full
recovery of all the pipeline costs. These releases maintain Avista's long-term rights to the
transportation capacity without incurring the costs of waiting until demand increases and
the capacity is required. At the end of these release terms, Avista surveys the market
against the IRP to determine if these contracts should be reclaimed or released, and for
what duration. Through this process, Avista retains the rights to vintage capacity without
incurring the costs or having to participate in future pipeline expansions that will cost more
than current capacity.
On a shorter term, excess capacity not fully utilized on a seasonal, monthly, or daily basis
can also be released. Market conditions often dictate less than full cost recovery for
shorter-term requirements. Mitigating some costs for an unutilized, but required resource
reduces costs to customers.
Segmentation
Through a process called segmentation, Avista creates new firm pipeline capacity for the
service territory. This doubles some of the capacity volumes at no additional cost to
customers. With increased firm capacity, Avista can continue some long-term releases,
or even reduce some contract levels, if the release market does not provide adequate
recovery. An example of segmentation is if the original receipt and delivery points are
from Sumas to Spokane. Avista can alter this path from Sumas to Sipi, Sipi to Jackson
Prairie, Jackson Prairie to Spokane. This segmentation allows Avista to flow three times
the amount of natural gas on most days or non-peak weather events. In the event of a
peak day, and the transport needs to be firm, the transportation can be rolled back up to
ensure the natural gas will be delivered into the original firm path.
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Chapter 5: Gas Markets and Current Resources
Storage
As a one-third owner of the Jackson Prairie Storage facility, Avista holds an equal share
of capacity (space available to store natural gas) and delivery (the amount of natural gas
that can be withdrawn daily).
Storage allows lower summer-priced natural gas to be stored and used in the winter
during high demand or peak day events. Like transportation, unneeded capacity and
delivery can be optimized by selling into a future higher priced market. This allows Avista
to manage storage capacity and delivery to meet growing peak day requirements when
needed.
The injection of natural gas into storage during the summer utilizes existing pipeline
transport and helps increase the utilization factor of pipeline agreements. Avista employs
several storage optimization strategies to mitigate costs. Revenue from this activity flows
through the annual PGA process and passed back to customers.
Commodity and Transportation Optimization
Another strategy to mitigate transportation costs is to participate in the daily market to
assess if unutilized capacity has value. Avista seeks daily opportunities to purchase
natural gas, transport it on existing unutilized capacity, and sell it into a higher priced
market to capture the cost of the natural gas purchased and recover some pipeline
charges. The amount of recovery is market dependent and may or may not recover all
pipeline costs but does mitigate pipeline costs to customers.
Combination of Resources
Unutilized resources like supply, transportation, storage, and capacity can combine to
create products that capture more value than the individual pieces. Avista has structured
long-term arrangements with other utilities that allow available resource utilization and
provide products that no individual component can satisfy. These products provide more
cost recovery of the fixed charges incurred for the resources while maintaining the rights
to utilize the resource for future customers' needs.
Resource Utilization Summary
Avista manages the existing resources to mitigate the costs incurred by customers until
the resource is required to meet demand. The recovery of costs is often market-based
with rules governed by the FERC. Avista is recovering full costs on some resources and
partial costs on others. The management of long- and short-term resources meets firm
customer demand in a reliable and cost-effective manner.
Renewable Natural Gas
Avista currently purchases renewable natural gas using Renewable Thermal Credits
(RTCs). Avista contracts using a project construct where Avista is the purchaser of a
smaller volume of a total project's RTCs, and the remaining environmental benefits are
Avista Corp 2025 Natural Gas IRP 134

Chapter 5: Gas Markets and Current Resources
sold. In this agreement a certain percentage can be claimed and transferred to Avista
when called upon while the remainder are sold into the Low Carbon Fuel Standard (LCFS)
and Renewable Identification Number (RIN) markets to help offset the total cost of the
RTCs obtained. Using this construct, Avita's percentage of RTCs is adjustable and can
be optimized depending on market conditions in the RIN and LCFS markets in addition
to Avista's needs based on climate programs, although pricing is subject to the value of
alternative markets. Avista's expected RTC greenhouse gas reduction volumes from
these arrangements are shown in Figure 5.9 and the expected pricing per metric ton is
shown in Figure 5.10 and reduces greenhouse gas emissions as per the final rules of the
CCA and CPP.
Figure 5.9: Avista Contracted RTCs Total Volume
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Chapter 5: Gas Markets and Current Resources
Figure 5.10: Avista Average Expected Price of RTCs Under Contract
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a $150
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Voluntary Renewable natural gas allows Washington, Idaho, and Oregon natural gas
customers to:
• Continue to enjoy the reliability and comfort of natural gas
• Tap into a local carbon-neutral resource
• Help repurpose existing waste streams
• Subscribe for as little as $5 per month
• Start or stop at any time, with no contract, while supplies last
Avista's RNG program supports RNG suppliers, including local and regional farms,
landfills, green energy companies and municipalities, to capture the methane associated
with these waste streams and purify it to make RNG.
Figure 5.11 illustrates the number of customers participant by state in Avista's voluntary
RNG program, as of November 2024. The program started in 2021 in Washington and
2022 in Idaho and Oregon. Each state appears to show active enrollments have flattened
off to levels reached in the initial program year.
Avista Corp 2025 Natural Gas IRP 136

Chapter 5: Gas Markets and Current Resources
Figure 5.11: Participants by State
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Chapter 5: Gas Markets and Current Resources
This Page is Intentionally Left Blank
Avista Corp 2025 Natural Gas IRP 138

Chapter 6: Supply-Side Resource Options
6. Supply-Side Resource Options
Section Highlights:
• Avista models both gas supply options and storage resources.
• Future competitive acquisition processes may identify new or existing resources
using different technologies with differing costs, sizes, or operating characteristics.
• Avista contracted with ICF to develop inputs for alternative fuel costs and volumes.
• The Inflation Reduction Act (IRA) tax incentives are included in resource costs.
• Renewable natural gas is modeled as a purchase gas agreement rather than utility
ownership.
This chapter discusses fuel supply and delivery options to meet future net energy
demand. Avista's objective is to provide a reliable gas service at reasonable prices. To
help achieve this objective, Avista evaluates a variety of supply-side resources to build a
diversified gas supply portfolio. In addition, Avista must be able to deliver fuels to
customers via access to pipelines or storage within the system. Figure 6.1 is an illustration
of the three components of the IRP's selection process, where demand and resource
options meet in the darker shades with compliance, storage, and fuels. There is not a
single solution to meeting these elements and all options, therefore a combination of
options is considered within the IRP analysis, but this chapter focuses on alternative fuels
to natural gas and storage. A summary of the alternative fuel options can be found at the
end of this chapter in Table 6.7.
Figure 6.1: Demand and Resource Options
Compliance
Mechanisms
•ccl
•Allowances
•CCUS
•RTC
Fuel / Reduced
Demand Storage
•Natural Gas •JP(Owned)
•Alternative Fuels •Propane
•Electrification •LNG
•Energy Efficiency/DR
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Chapter 6: Supply-Side Resource Options
Gas Storage Options
For this IRP, Avista is modeling storage options to address reliability and resiliency issues
recently seen in January 2024. This weather event brought a new set of challenges to the
Northwest on both the electric and natural gas systems. Weather across Avista's LDC
service territory reached near peaks in the Northern system and combined with freezing
equipment issues at Crowsnest compressor feeding GTN led to a reduced capacity of
volumes. Jackson Prairie (JP) storage also had a communications line issue over a few
hours with mitigation leading to opening the gate station from JP to "free flow" as needed.
A new communication line was run to the equipment and the facility was back to normal
operating capabilities later in the day on January 13, 2024. Avista includes both Propane
and Liquified Natural Gas (LNG) as a capacity option to address resiliency for high
demand scenarios. These resources are selectable within the optimization model if found
to be cost effective but may also be considered to address the risk of lost pipeline capacity
as a resiliency solution.
Propane Storage
A propane storage facility is being modeled with a single day deliverability of 30,000 Dth
equivalent energy. This storage facility could be placed on land currently owned by Avista,
pending site and environmental approvals, and uses air injection to bring down the energy
content to a pipeline quality standard. Each tank is considered at 10,000 Dth of capacity
equivalent and could be filled concurrently as withdrawals take place dependent on
supply availability. A total of roughly 328,000 gallons of propane would be required to fill
this facility considering a low heating value of 91,500 btu per gallon or 10.93 gallons per
dekatherm. This facility assumes two full-time equivalent employees per the
manufacturer's estimates. Plant and air injection electricity cost is also included and is
based on EIA national electricity costs and emissions per MWh. Capital costs are placed
into a revenue requirement model where taxes, fees and cost of capital are included to
estimate a yearly revenue requirement over its assumed 20-year life. An environmental
benefit of propane is it is considered zero emissions in the Clean Air Act, Climate
Commitment Act and the Climate Protection Plan meaning no offsets are needed to use
the facility other than the fixed and variable costs as shown in 6.2.
Avista Corp 2025 Natural Gas IRP 140

Chapter 6: Supply-Side Resource Options
Figure 6.2: Propane Storage Fixed and Variable Costs - Dth per Day (nominal $)
$0.60
a
Fixed Costs Variable Costs
p $0.50
L
a�
a
$0.40
0
L
Q $0.30
$0.20
0
Z $0.10
$0.00
W r- 00 T O N M � N W ti 00 C9 O N M 1* N
00 O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Liquified Natural Gas (LNG)
Avista could construct or partner to build a liquefaction LNG facility in the service area.
Doing so could use excess transportation during off-peak periods to fill the facility, avoid
tying up transportation during peak weather events, and it may avoid additional annual
pipeline charges.
Construction would depend on regulatory and environmental approval as well as cost-
effectiveness requirements. Preliminary estimates of the construction, environmental,
right-of-way, legal, operating and maintenance, required lead times, and inventory costs
indicate company-owned LNG facilities have significant development risks. As noted
above, liquified natural gas provides the ability to store multiple times the volume of
natural gas or RNG into a much smaller footprint. This energy can be used on peak days
or where supply is constrained. In the event of a deliverability constraint, it may be used
for either Avista's electric generation resources or the LDC. The model assumes only
LDC, but a cost sharing mechanism between these services may be considered in an
integrated system planning type model where this is a shared storage resource. Further,
Avista could offer existing pipeline capacity releases or other storage resource releases
to lessen the cost of such a facility. Avista did not include these benefits in this IRP at this
time but will evaluate these opportunities prior to the 2027 plan or when making a decision
Avista Corp 2025 Natural Gas IRP 141

Chapter 6: Supply-Side Resource Options
on acquiring storage capacity. To estimate the capital costs for LNG, there are three'
recently built or planned facilities to use as proxy estimates, resulting in $200 million for
an applicable facility.
As with the propane storage, a revenue requirement is estimated, but in this case an
asset life of 50 years is used, producing an annual revenue requirement for the capital
invested. Withdraw and injection estimates, plant and liquefaction electricity,
maintenance, pipeline and interconnect, days to fill, daily liquefaction amounts, and plant
operations are all considerations involving LNG. The storage facility modeled is 1 Bcf and
can deliver 1/10t" of this volume per day. Figure 6.3 illustrates the revenue requirement
for this capital investment through the forecast timeframe on a capacity basis of dollars
per dekatherm per day. Fuel costs are available within CROME for the alternative
resources as discussed in this chapter and natural gas resources as discussed in :napter
5. Plant cycling would help to reduce these costs as would market optimization but are
not considered in the cost forecast below but are not considered within the optimization
model for this plan.
Figure 6.3: LNG Storage Fixed and Variable Priced — Dth per Day (nominal $)
$0.20
� $0.18
■ Fixed Cost Variable Cost
o $0.16
L
a $0.14
0
$0.12
c, $0.10
$0.08
$0.06
o $0.04
z
$0.02
$0.00
W r` CO On O N M Iq U) W r` 00 M O N M qI U1
N N N N M M M M M M M M M M qI qIqCT qCT qCT qI
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Two projects from We® Energies- Ixonia and Bluff Creek (WI) and a proposal by (NM)
Avista Corp 2025 Natural Gas IRP 142

Chapter 6: Supply-Side Resource Options
Capacity Options Considered Outside the IRP
In addition to the capacity options for storing gas discussed above, Avista does consider
other options when they are available. These options are generally not modeled in the
IRP unless specific information is available regarding the opportunity to select these
resources.
Capacity Release Recall
Pipeline capacity not utilized to serve core customer demand is available to sell to other
parties or optimized through daily or term transactions. Released capacity is generally
marketed through a competitive bidding process and can be on a short-term (month-to-
month) or long-term basis. Avista actively participates in the capacity release market with
short-term and long-term capacity releases. Avista assesses the need to recall capacity
or extend a release of capacity on an on-going basis. The IRP process evaluates if or
when to recall some or all long-term releases.
Existing Regional Pipeline Capacity
The GTN interconnection with the Ruby Pipeline provides GTN the physical capability to
provide a limited amount of firm back-haul service from Malin with minor modifications to
their system. Fees for utilizing this service are under the existing Firm Rate Schedule
(FTS-1) and currently include no fuel charges. Additional requests for back-haul service
may require additional facilities and compression (i.e., fuel).
This service can provide an interesting solution for Oregon customers. For example,
Avista can purchase supplies at Malin, Oregon and transport those supplies to Klamath
Falls or Medford. Malin-based natural gas supplies typically include a higher basis
differential to AECO supplies but are generally less expensive than the cost of forward-
haul transporting traditional supplies south and paying the associated demand charges.
The GTN system is a mileage-based system, so Avista pays only a fraction of the rate if
it is transporting supplies from Malin to Medford and Klamath Falls. The GTN system is
approximately 612 miles long and the distance from Malin to the Medford lateral is only
about 12 miles.
In-Ground Storage
In-ground storage provides advantages when natural gas from storage can be delivered
to Avista's city gates. It enables deliveries of natural gas to customers during peak cold
weather events. It also facilitates potentially lower-cost supply for customers by capturing
peak/non-peak pricing differentials and potential arbitrage opportunities within individual
months. Although additional storage can be a valuable resource, without deliverability to
Avista's service territory, this storage cannot be an incremental firm peak serving
resource.
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Chapter 6: Supply-Side Resource Options
Jackson Prairie
Jackson Prairie is a potential resource for expansion opportunities. Any future storage
expansion capacity does not include transportation and therefore cannot be considered
an incremental peak day resource. However, Avista will continue to look for exchange
and transportation release opportunities to fully utilize these additional resource options.
When an opportunity presents itself, Avista assesses the financial and reliability impact
to customers. Due to the growth in the region, and the need for new resources, a future
expansion is possible, though a robust analysis would be required to determine feasibility.
Currently, there are no plans for immediate expansion of Jackson Prairie.
Other In-Ground Storage
Other regional storage facilities exist and may be cost effective. Additional capacity at
Northwest Natural's Mist facility, capacity at one of the Alberta area storage facilities,
Questar's Clay Basin facility in northeast Utah, Ryckman Creek in Uinta County, Wyo.,
and northern California storage are all possibilities. Transportation to and from these
facilities to Avista's service territories continues to be the largest impediment to these
options. Avista will continue to look for exchange and transportation release opportunities
while monitoring daily metrics of load, transport, and the market environment.
Compressed Natural Gas (CNG)
CNG is another resource option for meeting demand peaks and is operationally similar to
LNG. Natural gas could be compressed offsite and delivered to a distribution supply point
or compressed locally at the distribution supply point if sufficient natural gas supply and
power for compression is available during non-peak times. Avista does not consider this
option in higher level resource planning due to the small facility size but could be an
alternative for a non-pipe alternative to distribution expansion.
Alternative Fuels Resource Supply Options
A coordinated study between Avista, Cascade Natural Gas, and Northwest Natural
utilized ICF2 to develop resource potential volumes and prices for Carbon Capture,
Utilization and Storage (CCUS), Hydrogen (H2), Renewable Natural Gas (RNG),
Renewable Thermal Credit (RTC), and Synthetic Methane (SM) in their various
production types, facility sizes, volumes and any incentives offered to assist with the costs
of their production. A full report is included in Appendix 6 summarizing methodologies
and assumptions. High level summaries of this report are also included herein.
Technical Potential Resource Volumes
Technical potential resource volumes were estimated by ICF for estimated availability in
the Northwest and Nationally. Split by estimated number of customers for each local
distribution company (LDC) in Oregon and Washington. The volumes were then modeled
by Avista in CROME with local availability potential in the Northwest for all alternative
2 ICF: Strategic Consulting & Communications for a Digital World I ICF
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Chapter 6: Supply-Side Resource Options
resources except RTCs as National potentials were the only estimates requested.
Volumes are considered local and within Avista's distribution system with the ability to be
injected into storage in days of lower demand with rates and tariffs associated with the
pipelines to get the gas to the storage destination.
Pricing
Expected prices are broken down between Northwest and national technical potential. All
prices consider the Inflation Reduction Act (IRA) incentives and are shown in nominal
dollars. Additional assumptions are as follows:
• Prices assume a first mover access to alternative fuels.
• Prices are for the Northwest located alternative fuels and Nationally located
Renewable Thermal Credits (RTC).
• Hydrogen (H2) & Synthetic Methane (SM) prices will be treated as a purchase gas
agreement where Avista would sign a term contract, each year, with the producer
for these prices through the forecast.
• Renewable Natural Gas (RNG) assumes a proxy ownership with costs levelized
over 20 years.
• RTC considers a production cost plus, where prices cover all costs.
\/nIllmnr
Expected fuel volumes are broken down between Northwest and National technical
potential. These volumes assume a first mover access to alternative fuels and are
weighted by US population for states where some form of climate policy is in place or
demand is expected. Avista modeled physical potential volumes are from Avista's
weighted share in the Northwest and intended to represent all volumes available to Avista
in the United States. RTCs are the only National located resource potential considered in
the plan and assumes physical pipeline accessibility to meet Washington's Climate
Commitment Act (CCA) and Oregon's Climate Protection Program (CPP) program rules.
The fuel volumes for Avista's potential are based on our pro-rata share of Northwest
meters. This calculation is demonstrated in Table 6.1 and is broken out by the number of
meters between LDCs in Oregon and Washington as of the year 2023. Figure 6.4 shows
the total technical potential of Avista's share of the technical potential compared to the
percentage of actual share modeled. Figure 6.5 shows the fuel type share by percentage
of modeled total volume. Whereas Figure 6.6 demonstrates the percentage of available
total volumes in dekatherm equivalent.
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Chapter 6: Supply-Side Resource Options
Table 6.1: Volumetric Breakout by LDC in the Northwest
Avista 379,223 15.810%1,
Cascade 316,929 13.2%
Northwest Natural 799,250 33.4%
Puget Sound Energy 900,000 37.6%
Total 2,395,402 100.0%
Figure 6.4: Modeled Volumes Compared to Technical Potential Volumes
1,400 0! Technical Potential Total °
Modeled Available Volumes Total
1,200 Modeled %of Technical Potential 10% a?
cn o
a
0 1,000 8%
800
6%
600 ~
o
� 4%
400
Q �
aD
200 2% Z
o
0%
C0 I` co M O N M 11 LO (fl r` 00 a) CD N M 40 W)
N N N N co co co co co co co M M M � � � � ItT 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 6: Supply-Side Resource Options
Figure 6.5: Percentage of Total Volumetric Availability by Source
N 100% .
E 90%
0 80%
> 70%
60%
30%
Q 40%
30%
20% _
2 10%
p 0%
o N N N N M M M M M M M M M M "I Nt Iq Iq '9t "I
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
CCUS (Dth eq) H2 RNG RTC SM
Figure 6.6: Annual Modeled Volumes by Alternative Fuel Type
140
■ CCUS (Dth eq) H2 ■ RNG ■ RTC ■ SM
120
0 100
V)
80
c
0_ 60
40
20
CD I` 00 M O N M q* L0 CD r` 00 M O N CO Iq N
N N N N M M M M M M M M M M q � Ict 'q 'Rt
O O O O O O O M O O O O O M O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 6: Supply-Side Resource Options
Renewable Natural Gas (RNG)
Renewable Natural Gas, or biogas, typically refers to a mixture of gases produced by the
biological breakdown of organic matter in the absence of oxygen. RNG can be produced
by anaerobic digestion or fermentation of biodegradable materials such as woody
biomass, manure or sewage, municipal waste, green waste, and energy crops.
Depending on the type of RNG there are different factors to quantify methane saved by
its capture as methane up to 343 times the greenhouse gas intensity as compared to
carbon dioxide. Each type of RNG has a different carbon intensity as compared to natural
gas as shown in Table 6.2.
fable 6.2: Carbon Intensity (lbs per mmbtu)4
2040 04
Animal Manure -212.24 -212.24 213.33 213.33 213.43 213.43
Food Waste -71.94 -71.94 -73.03 -73.03 -73.13 -73.13
Landfill Gas 14.08 14.08 13.01 13.01 12.91 12.91
Waste Water 14.54 14.54 13.17 13.17 13.04 13.04
RNG is a renewable fuel, so it may qualify for renewable energy subsidies. Once
processed, RNG can be used by boilers for heat, as power generation, compressed
natural gas vehicles for transportation or directly injected into the natural gas grid. The
further down this line, the greater the need for pipeline quality gas. Avista modeled RNG
with the option to inject into JP rather than use in low demand months and will help with
the intrinsic value compared to natural gas. Geography is also generic as understanding
exact location is problematic due to the unknown locations of these potential projects.
RNG projects are unique, so reliable cost estimates are difficult to obtain. Project
sponsorship has many complex issues, and the more likely participation in such a project
is as a long-term contracted purchaser. Avista considered biogas as a resource in this
planning cycle and depending on the location of the facility it may be cost effective. This
is especially the case when found within Avista's internal distribution system where
transportation and fuel costs can be avoided. For more information about RNG and its
potential uses in energy policy within Avista territories please see urial)rer .
Each RNG project will vary in size, location, and distance to interconnection with the
pipeline, feedstock type, gas conditioning equipment and requirements and operating
costs. In general terms, new RNG projects can take two to three years to develop
depending on project size and scope. This IRP considers the first year of availability to
any RNG resource in 2030.
3 https://www.ipcc.ch/
4 ICF Alternative Fuels Study—Appendix 6
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Chapter 6: Supply-Side Resource Options
To bridge the gap between ownership or purchasing from a producer, it was made
available in the model to assume a quantity taken each year carries forward thru the end
of the study. Table 6.3 shows the RNG options and reference name as well as a
description of each type of feedstock.
Table 6.3: Renewable No`----' Options
� -
Animal AM 4, AM 5 Manure produced by livestock, including dairy cows,
manure beef cattle, swine, sheep, goats, poultry, and horses.
Commercial, industrial and institutional food waste,
7
Food waste FW 3 including from food processors, grocery stores,
cafeterias, and restaurants.
Anaerobic Landfill gas LFG 1, LFG 2, The anaerobic digestion of organic waste in landfills
Digestion (LFG) LFG 3, LFG 4, produces a mix of gases, including methane (40-60%).
LFG 5
Water Wastewater consists of waste liquids and solids from
resource WW 1, WW 2, household, commercial, and industrial water use; in the
recovery WW 3, WW 4, processing of wastewater, a sludge is produced, which
facilities WW 5 serves as the feedstock for RNG.
WRRF
ICF developed assumptions for the capital expenditures and operation costs for RNG
production from the various feedstock and technology pairings. ICF characterized costs
based on a series of assumptions regarding the production facility sizes (as measured by
gas throughput in units of standard cubic feet per minute [SCFM]), gas upgrading and
conditioning and upgrading costs (depending on the type of technology used, the
contaminant loadings, etc.), compression, and interconnect for pipeline injection. ICF also
included operational costs for each technology type. Price estimates are illustrated in
Figure 6.7, 6.8, and 6.9 assume both the RTC and brown gas (energy) as a bundled price.
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Chapter 6: Supply-Side Resource Options
Figure 6.7: Higher Cost RNG Price by Source (nominal $)
$100
$90
_ $80
o $70
L
Q $60
7E
$50
$40
z $30
$20
$10 RNG - AM 4 RNG - AM 5 RNG - FW 3
RNG - LFG 1 —RNG - WW1 RNG - WW2
CO r` O O O N Mq* CO r` O O O N MIq
N N N N M M M M M M M M M M 1 "Ilt Iq Iq "Ilt
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 6.8: Lower Cost RNG Price by Source (nominal $)
$40
LFG 2 — LFG 3 LFG 4 LFG 5
$35 WW 3 —WW 4 WW 5
o $30
L
CL $25
$20
o $15
z
$10
$5
$-
CO f` O O O N M I L0 CD r~ O O O N M NT Lr)
N N N N M M M M M M M M M M N* Nt 10 11 11 "Itt
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
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Chapter 6: Supply-Side Resource Options
=figure 6.9: RNG Modeled Resource Potential Volumes
14,000
12,000
10,000
ca _
L
8,000 _ —
6,000
4,000 ■ ■
2,000 � � ■ ■ ■ ■ ■ ■ soon
Co r~ co M CD Ir.- N M � LO Co r~ co M CDN co � Lo
N N N N M M M M M M M M M cM � qq � � � �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
AM 4 AM 5 FW 3 ■ LFG 1 LFG 2 ■ LFG 3 ■ LFG 4
LFG 5 WW 1 WW 2 WW 3 WW 4 ■WW 5
Renewable Thermal Certificate (RTC)
RTCs are the certified volume of energy that provides proof of production of renewable
gas but is not directly delivered to Avista's system. This gas can be in the form of any of
the alternative fuel options covered in this chapter but modeled based on the production
of RNG. The energy from the production volumes is not delivered gas to Avista
customers, but rather an offset for the use of natural gas. Program requirements for
Washington's CCA and Oregon's CPP describe compliance can be achieved by fuels
where a physical pathway beginning at the production site and to the area of use can be
identified. Avista does not assume compliance with RTCs where the gas is physically
stranded or impossible to use based on location and interconnection. Avista's
assumptions for RTC pricing for this IRP are included in Figure 6.10 and Figure 6.11 with
the same RNG types of production and feedstock as discussed above.
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Chapter 6: Supply-Side Resource Options
Figure 6.10: Higher Cost RTCs Price by Source (nominal $)
$160
$140
o $120
a $100
$80
E $60
0
z $40
$20 RTC (AM 4) RTC (AM 5) —RTC (FW 3)
RTC (LFG 1) RTC (WW 1) —RTC (WW 2)
$-
CD f` O M O N M N* U') c.D I,- O O O N M N* In
N N N N M M M M M M M M M M IqNI, Iq qq Iq Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 6.11: Lower Cost RTCs Price by Source (nominal $)
$60
RTC (LFG 2) — RTC (LFG 3) —RTC (LFG 4)
RTC (LFG 5) RTC (WW 3) RTC (WW 4)
$50 RTC (WW 5)
s
0
$40
$30
0 $20 - -
z
$10
$-
(.D I- CO Q) O T- N M q LO CD r- CO O O N M qt LO
N N N N M M M M M M M M M M Iq Iq Iq Iq Iq Iq
O O O O O O O O O O O O O O O O O 00 O
N N N N N N N N N N N N N N N N N N N N
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Chapter 6: Supply-Side Resource Options
Hydrogen
Hydrogen (H2) is a fuel source with a long history and great potential to help solve future
energy needs. Its energy factor, as measured in a kilogram (kg) of low heating value
(LHV), is roughly equivalent to a gallon of gasoline. Hydrogen can be made from any
energy source including nuclear (pink H2) and electric renewable energy (green H2). With
expanding renewable electricity production, the ability to create green hydrogen from this
energy is moving from concept to market throughout the world. Some drawbacks to
hydrogen include needing three times the volume of pipeline capacity to provide the same
energy as natural gas. Avista assumes a maximum blend rate with natural gas in the
pipelines system to be 20%5, but the energy blend can reduce current pipeline capacity
and may not be possible to obtain this limit if the underlying delivery system is
constrained. Hydrogen can also impact functionality of appliances and end uses based
on the ability to contain the lightest element on earth combined with less energy delivered
on a cubic foot basis when compared to natural gas. This process of using power to
separate water into hydrogen and oxygen is known as power to gas (P2G) through
electrolysis and can provide energy storage, a critical piece to electric grid
decarbonization yet to be developed on a large enough or cost-effective scale. Most
hydrogen is currently made by reforming natural gas, also known as grey H2. The
emission ranges shown in Table 6.4 include all types of hydrogen production and qualified
facilities, which are to be required to meet certain wage and apprenticeship requirements
as defined in the IRA.
Table 6.4: Production Types of Hydrogen:
Feedstock kg Hydrogen Production Technology Cirange Former Color
Natural Gas Hydrogen produced from SMR, no carbon 10- 14 Gray
capture
Coal Hydrogen produced from coal gasification 20-30 Brown
Natural Gas Hydrogen produced from SMR/ATR with 1.8-2.6 Blue
97%+ CCS
Natural Gas & RNG Hydrogen produced from SMR/ATR with 0-0.45 Blue
97%+ CCS
RNG Hydrogen produced from methane <0 Turquoise
pyrolysis Microwave Pyrolysis)
Natural Gas Hydrogen produced from methane <2.5 Turquoise
pyrolysis Microwave Pyrolysis)
Renewable Hydrogen produced via electrolysis from 0-2.6" Green
Electricity renewable energy's
Nuclear Energy Hydrogen produced via electrolysis from <1 Pink
nuclear energy
Several governing bodies have begun to define "Clean Hydrogen" according to its carbon
intensity. In the US, the definition of Clean Hydrogen was established to be less than 4
5 https://www.prnewswire.com/news-releases/socalgas-among-first-in-the-nation-to-test-hydrogen-
blending-in-real-world-infrastructure-and-appliances-in-closed-loop-system-301389186.htmI
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Chapter 6: Supply-Side Resource Options
kg CO2e/kg H2 under the Bipartisan Infrastructure Law and further defined by categories
under the Inflation Reduction Act (IRA) which created a new hydrogen production tax
credit under Section 45V of the tax code. Only projects demonstrating life cycle GHG
emissions of less than 4 kg CO2e/kg H2 produced are to qualify, as demonstrated in the
Figure 6.12 and Figure 6.13 below. Further details of the IRA are discussed in Chapter 7.
These costs are assumed to be located at or near load centers in Avista owned
distribution.
Two new types of hydrogen have been modeled in the 2025 IRP. The first is blue
hydrogen and like gray hydrogen can use steam methane reforming (SMR) using steam
from electricity to split water. Blue hydrogen adds additional production capabilities with
autothermal reforming (ATR) using chemical reactions (partial oxidation and steam
reforming) to generate the heat needed to split water through electrolysis and adds in
carbon capture and storage. The second type of hydrogen modeled is turquoise, using
microwave radiation6, and produces a solid form of carbon known as carbon black, this
bi-product can be sold to manufacturers for other products such as tires. Gray, brown,
and pink forms of hydrogen were not modeled in this IRP as adding emissions to Avista's
supply does not help with climate goals (gray, brown) and pink hydrogen or hydrogen
produced from nuclear electricity is unlikely in our region as the power would more likely
be used directly by the electric grid.
Figure 6.12: Hydrogen Cost Estimates
$100
—Blue Hydrogen 1
—Green H2-Wind+Electrolysis 1
$80 —Green H2-Solar+Electrolysis 1
o Microwave Pyrolysis 1
L
n. $60
�a
.E
$40
0
Z
$20
$-
CD r` 00 Q) O N M Iq to CD r~ 00 O O N M q1 V)
N N N N M M M M M M M M M M "I
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
s Microwave Pyrolysis - an overview I ScienceDirect Topics
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Chapter 6: Supply-Side Resource Options
Figure 6.13: Hydrogen Daily Modeled Volumes
100,000
90,000
80,000
70,000
0 60,000
50,000
�- 40,000
o
30,000
20,000
10,000
W r` CO M CD N M Iq LO W r` CO M CD N M 'q Ln
N N N N M M M M M M M M M M Iq IqIq Iq Iq
CD O O O CD O O O O O O O CD O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Blue Hydrogen 1 Green H2-Wind+Electrolysis 1
GreenH2-Solar+Electrolysis 1 Microwave Pyrolysis 1
Table 6.5 shows cost inputs from ICF assumptions involving the use of electrolyzers in
the production of hydrogen to derive the costs as shown above and include electrolyzer
size, energy consumption rate per kWh and water costs among others.
Table 6.5: Electrolyzer Facility Production Cost Inputs
put Value Comments -A
Sample Facility Size
Electrolyzer Size 220 MW Based on projects with which ICF is familiar
Annual Production 20,000,000 kg Based on projects with which ICF is familiar
Target
Energy and Water Inputs
Dependent on energy
Renewable Power resource and location Assuming energy from solar, wind and nuclear
Capacity Factor (national vs. regional sources
averages)
Electrolyzer Energy Based on projects with which ICF is familiar and
Consumption Rate 53 kWh/kg ranges from original equipment manufacturers
(OEMs)
BoP Energy g kWh/kg Based on projects with which ICF is familiar and
Consumption Rate ranges from OEMs
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Chapter 6: Supply-Side Resource Options
Dependent on Based on AEO projections for solar and wind
resource type (solar, LCOEs and ICF estimates from NREL for
Electricity Cost wind, nuclear or nuclear LCOE; RECs assumed to come at a
renewable energy placeholder value of 5% premium to the LCOE
certificates [RECs]) which is varied in the Monte Carlo analysis due
to the regulatory uncertainties
Water Intake Rate 2.64 gal/kg Based on projects with which ICF is familiar and
ranges from OEMs
Industrial utility water with approximately 1%
annual escalation from DOE's
Water Cost $5.63/kgal
Office of Scientific and Technical Information
(OSTI)
Operation Inputs
Stack Membrane Life 10 years Based on projects with which ICF is familiar
Life of Electrolyzer 80,000 hours Based on projects with which ICF is familiar
Equipment
Annual Degradation o Conservative estimate; Ievelized degradation
Rate 1 /o factor was assumed to have minimal impact and
not included in analysis
Operating year 333-353 days Based on projects with which ICF is familiar
Annual Labor Costs $2.95MM ICF's estimate for standalone electrolyzer facility
with -25 staff
Membrane
Replacement Cost as 30% Based on projects with which ICF is familiar
% of Direct Ca ex
Annual Maintenance 3% Based on projects with which ICF is familiar/o as of Capex
Project Finance and Capital Costs
PEM Electrolyzer $1050/kW Based on projects with which ICF is familiar and
bids from OEMs
Total Installed Cost 2 Based on projects with which ICF is familiar; can
Factor range from 2-2.7 depending on BOP
Learning Curve Rate 22% ICF's internal model
for Total System
WACC 4% Provided by utilities; varied in the Monte Carlo
analysis
Loan Duration 20 years Based on projects with which ICF is familiar
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Chapter 6: Supply-Side Resource Options
Synthetic Methane
Synthetic Methane is the creation of natural gas through an artificial process. This
analysis considers two primary forms of creation:
3. Biomass gasification includes energy crops with high energy content, like agricultural
residues or forestry residues. The material goes through a thermal gasification
process to produce RNG. Thermal gasification generates synthesis gas containing
hydrogen and carbon monoxide.
4. Power to Gas, for this IRP analysis, green hydrogen is created using water electrolysis
with solar energy, then the hydrogen is bonded with a carbon source. The carbon
source could be from an industrial facility, power plant, or air capture. For this IRP a
biogenic carbon source is assumed. The capacity of the electrolyzer needed to
produce the synthetic methane is summarized in Table 6.6 where a 220 MW solar
facility combined with a carbon source producing 188,553 metric tons of CO2 can
produce 3.8 million dekatherm equivalent energy per year.
Table 6.6: Green H2-Biogenic CO2
VariableVF
GreenW-Solar(NW)-BiogenicCO2
Electrol zer MW 220
Capacity factor, methanation/electrolysis % 95%
Electrolyzer Energy Consumption kWh/kg 53.00
H2 Production /Consumption t/y 34,544
CO2 Consumption t/y 188,553
S nCH4 Production t/y 68,732
SynCH4 Production mmBtu/y 3,831,161
Synthetic methane is considered pipeline quality and acceptable for use in the current
natural gas system infrastructure without any upgrades or alterations as it is, in essence,
natural gas. This fuel can also help bridge the gap for excess electricity if produced from
an electrolyzer and act as a form of energy storage during period of low demand to a
period of higher demand. Green hydrogen costs are discussed above and provide the
energy portion of synthetic methane. Synthetic methane is a combination of green
hydrogen and carbon capture costs per dekatherm. Cost estimates for synthetic methane
are included in Figure 6.14 and volumes can be found in 6.15. For this IRP, Avista is
modeling three different production levels for the biomass options to represent the project
scale required if the fuel alternative is selected.
Avista Corp 2025 Natural Gas IRP 157

Chapter 6: Supply-Side Resource Options
Figure 6.14: Synthetic Methane Cost Estimates
$100
Biomass 1
$90 Biomass 2
Biomass 3
$80 Green H2-BiogenicCO21
o $70
L
a $60
$50
$40
Z $30
$20
$10
$-
c fl r~ CO M O N Mqr Ln c.0 ti GO M O N M 11 In
N N N N M M M M co M M M M M Iq � ICT Iq � let
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 6.15: Synthetic ivietnane uauy ivioaewa volumes
25,000
20,000
15,000
0
L
a 10,000
L
5,000
i
CO r` W M Mr- N M m* LO (D r` W M O N M Iq LO
N N N N M M M M M M M M M M '9T 'q '9T 'q N*
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
Biomass 1 Biomass 2 Biomass 3 Green H2-BiogenicCO2 1
Avista Corp 2025 Natural Gas IRP 158

Chapter 6: Supply-Side Resource Options
Alternative Fuel Supply Price Risk
While weather is an important driver for the IRP, fuel price is also important. As seen in
recent years, significant price volatility can affect the resource portfolio. In deterministic
modeling, a single price curve for each scenario is used for analysis, these prices are
shown in the price forecasts above. There is uncertainty with new technology prices,
therefore, Avista used Monte Carlo simulation to test the resource portfolio and quantify
the risk to customers when prices do not materialize as forecast. Avista performed a
simulation of 500 draws to include varying fuel supply prices, to investigate whether the
Preferred Resource Strategy's total portfolio costs from the deterministic analysis are
within the range of occurrences in the stochastic analysis. This simulation of prices is
done for natural gas, RNG by anaerobic production type (dairy, landfill, solid waste, and
waste- water), hydrogen, and synthetic methane. Figure 6.16 to Figure 6.21 show the
average yearly price per dekatherm for the largest and most cost-effective units from the
ICF analysis, per draw and resource for the years 2030 through 2045, for each of the 500
draws. Statistics are also provided with each histogram and represent the raw data
results. This dataset can also be found in Appendix 6 for all modeled resources. An annual
request for proposal (RFP) will help to value these resources and availability to obtain the
least cost resource as compared to other available resources as bid into this process.
Other proposals outside of this process may arrive and will be valued under the same
methodology considering the least cost and risk solution.
Figure 6.16: RNG Landfill RNG (LFG 5) - $ per Dth (500 Draws)
140
Average: 10.10
120 Min: 6.10
Max: 15.24
100 5th % : 7.99
80 95th % : 12.44
Std. Dev.: 1.40
60
u_
40
20
0
M (0 0) N LO 00 1` O M (0 a) N LO 00
M Lq 1` O N � 1` 07 7 � (P 00 O M � 1` O N
. . . . . . . . . . . . . . . . . .
C0 (0 (0 1` 1` 1` 1­ 1` 00 00 00 00 0) 0) 0) 0) O O
- - - - - - - - - - - - - - - - -
O M (0 0) N LO 00 � R* ti O M (0 a) N LO
M Ul 1` O N � ti 07 � (P 00 O M Lq 00
C0 C0 (0 (0 1` 1` 1` 1­ 1` 00 00 00 00 0) 0) 0) ti O
u .... .... .... .... .... .... .... .... .... .... .... .... .... .... .... M O
Avista Corp 2025 Natural Gas IRP 159

Chapter 6: Supply-Side Resource Options
Figure 6.17: Dairy RNG (AM 5) - $ per Dth (500 Draws)
120
Average: 63.96
100 Min: 39.42
Max: 94.99
80 5th % : 51.62
95th % : 77.66
0 60 Std. Dev.: 8.18
Cr
a�
LL 40
20
0
N N N N N N N N N N N N N N N N N N
M q* M q* M q* M q* M q* M q* M q* M q* M q*
C N M M (6 00 ai r. N .4 W; f-z 00 O M 4 C6
q* q* q* q* q* q* q* M M M M M M to to co co co
- - - - - - - - - - - - - - - - - -
N N N N N N N N N N N N N N N N N N
q* M q* M q* m q* M q* M q* M q* M q M q* M
M C N M M (6 00 ai r. N .4 W; f_� 00 O M 4
M q* q* q* q* qq q* q* M M M M M M (0 co co co
Figure 6.18: Food Waste RNG (FW 3) - $ per Dth (500 Draws)
120
Average: 77.98
100 Min: 48.25
Max: 115.66
80 5th % : 63.10
95th % : 94.47
60
Cr Std. Dev.: 9.85
a�
LL 40
20
0
uO uO uO uO to to to uO u') uO u') u') uO uO u) u) u)
7 O M 00 f� (O q* CON O M CO I- CO M
. . . . . . . . . . . . . . . . .
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M M to M 1n W) co co (O (O co I- I- P­ P­ P­ 00
.. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
M M to M M to M to to to M M M M M M M
N 7 O M 00 f� CD W) qq M N � O M CO I- CO
. . . . . . . . . . . . . . . . .
00 O N M 1n f� M � M M f_z M � N 4 (6 00
Avista Corp 2025 Natural Gas IRP 160

Chapter 6: Supply-Side Resource Options
Figure 6.19: Wastewater Treatment RNG (WW 5) - $ per Dth (500 Draws)
90
Average: 14.46
80 Min: 8.54
70 Max: 21.99
60 5th % : 10.98
95th % : 18.38
60 Std. Dev.: 2.28
M
aci 40
uL 30
20
10
0
I- O co co O N U') OD r q* ti Co M to
O q* OD N co T_ O O Iq OD N P­ T_ O
. . . . . . . . . . . . . .
OD O O O O � � � N N M M 4 4
O O M co O N O OD P- O M
OD OD pj OR N CD O O q* OD N ti T_
'--' O O O T_ T_ T_ N N M M
T_ T_ T_ T_ T_ T_ T_ T_
.... .... .... .... .... .... .... .... .... ....
Fiaure 6.20: Hydrogen (GreenH2-Solar + Electrolysis1) - $ per Dth (500 Draws)
90
Average: 34.26
80 Min: 19.08
70 Max: 55.34
5th % : 22.55
U 60 95th % : 45.30
a 60 Std. Dev.: 7.78
M
aci 40
U
30
20
10
0
ti0 ti titi ti� ryb� ryh ry�o' ry�b do �O � ^ry
1�" 1�^ 1�^ tom" 1�^ 1�" 1�" 1�^ f�^ 1�^ 1�^
ti 4 ti CID IN- -I Q Q e. rye. rye. ryy. ryo. rye. �ryo. moo. .
Avista Corp 2025 Natural Gas IRP 161

Chapter 6: Supply-Side Resource Options
Figure 6.21: Synthetic Methane (Biomass 3) - $ per Dth (500 Draws)
100
Average: 30.30
90 Min: 16.44
80 Max: 45.30
70 5th % : 22.68
60 95th % : 37.69
W 50 Std. Dev.: 4.55
Cr
LL 40
30
20
10
0
N O 000 CR V N O 0000 W V N O 0000
. . . . . . . . . . . . . .
f— 00 00 OA O � N N M 4 6 6 6 f�
V_ V_ V_ N N N N N N N N N N
.. .. .. .. .. .. .. .. .. .. .. .. .. ..
q* N O 00 (0 q* N O 00 co q* N Co 00
(6 f_� 00 00 0A O T_ N N M 4 L6 (6 (6
V_ V_ V_ N N N N N N N N N
Finally, Table 6.7 summarizes the alternative fuel costs per dekatherm discussed above
in nominal dollars. These resources represent the fuels and unit specific values included
in the CROME model by type and incremental year to help show changes in cost over the
forecast horizon.
Avista Corp 2025 Natural Gas IRP 162

Chapter 6: Supply-Side Resource Options
Table 6.7: Alternative Fuels Costs per Dth (Nominal $)
2040 2045
Blue Hydrogen 1 $ 12.86 $ 14.43 $ 18.22 $ 37.27 $ 41.82
Green H2-Wind+Electrol sis 1 $ 36.41 $ 31.26 $ 33.16 $ 56.77 $ 62.13
Green H2-Solar+Electrolysis 1 $ 28.19 $ 25.61 $ 25.44 $ 39.28 $ 39.79
Microwave Pyrolysis 1 $ 33.40 $ 36.61 $ 43.59 $ 61.93 $ 69.92
AM 4 $ 35.86 $ 41.88 $ 51.36 $ 62.60 $ 76.80
AM 5 $ 47.90 $ 52.56 $ 59.85 $ 67.52 $ 75.99
FW 3 $ 58.61 $ 64.34 $ 73.00 $ 82.22 $ 92.53
LFG 1 $ 31.14 $ 34.72 $ 40.20 $ 46.32 $ 53.31
LFG 2 $ 14.79 $ 16.36 $ 18.86 $ 21.64 $ 24.70
LFG 3 $ 10.60 $ 11.68 $ 13.46 $ 15.44 $ 17.55
LFG 4 $ 8.63 $ 9.48 $ 10.92 $ 12.54 $ 14.22
LFG 5 $ 7.42 $ 8.13 $ 9.38 $ 10.77 $ 12.19
WW 1 $ 47.95 $ 53.65 $ 62.89 $ 73.00 $ 84.48
WW 2 $ 42.66 $ 47.63 $ 55.78 $ 64.64 $ 74.64
WW 3 $ 18.38 $ 20.23 $ 23.73 $ 27.35 $ 31.12
WW 4 $ 13.41 $ 14.66 $ 17.29 $ 19.94 $ 22.56
WW 5 $ 10.48 $ 11.39 $ 13.52 $ 15.62 $ 17.59
Biomass 1 $ 45.44 $ 49.68 $ 65.52 $ 73.71 $ 82.78
Biomass 2 $ 24.08 $ 26.31 $ 34.73 $ 39.22 $ 44.08
Biomass 3 $ 20.09 $ 21.93 $ 28.55 $ 32.26 $ 36.24
Green H2-Bio enicCO2 1 $ 41.54 $ 36.30 $ 36.81 $ 54.40 $ 55.87
RTC AM 4 $ 75.67 $ 83.26 $ 95.08 $ 107.70 $ 121.93
RTC (AM 5) $ 64.92 $ 71.34 $ 81.46 $ 92.23 $ 104.31
RTC FW 3 $ 79.31 $ 87.23 $ 99.33 $ 112.32 $ 127.02
RTC (LFG 1) $ 53.15 $ 59.41 $ 69.08 $ 79.91 $ 92.49
RTC LFG 2 $ 26.17 $ 28.91 $ 33.35 $ 38.26 $ 43.80
RTC (LFG 3) $ 18.41 $ 20.21 $ 23.26 $ 26.62 $ 30.32
RTC LFG 4 $ 14.59 $ 15.94 $ 18.33 $ 20.95 $ 23.78
RTC (LFG 5) $ 12.17 $ 13.24 $ 15.22 $ 17.39 $ 19.69
RTC WW 1 $ 73.58 $ 82.85 $ 97.75 $ 114.35 $ 133.66
RTC (WW 2) $ 65.11 $ 73.12 $ 86.13 $ 100.54 $ 117.21
RTC (WW 3) $ 26.63 $ 29.32 $ 34.35 $ 39.66 $ 45.41
RTC WW 4 $ 18.83 $ 20.53 $ 24.09 $ 27.74 $ 31.51
RTC (WW 5) $ 14.25 $ 15.38 $ 18.11 $ 20.82 $ 23.49
Avista Corp 2025 Natural Gas IRP 163

Chapter 6: Supply-Side Resource Options
Carbon Capture Utilization and Storage (CCUS)
CCUS considers the capturing and utilization of carbon or the storage of the physical
carbon elements. This is a form of carbon mitigation where the sources of capture can
vary between:
• Flue gases of power plants and industrial facilities burning fossil fuels or
biomass/biofuel,
• Process gas streams from industrial facilities (natural gas processing plants,
ammonia plants, methanol plants, petroleum refineries, steel mills, cement plants,
ethanol plants, etc.)
• Hydrogen plants using fossil fuels or biomass as feedstocks
• Air (through the application of direct air capture).
After capturing CO2, the next step is to purify and dehydrate the CO2, compress it for
transportation and then either (a) to inject it underground into an appropriate geological
storage site, where it is trapped and permanently stored in porous rock or (b) utilize it in
one or more of the ways shown in the chart below in Figure 6.22. The prices assumed for
carbon capture by type and total volumes for this IRP can be found in Figures 6.23 and
6.24. The costs include incentives from the IRA to help offset the total costs of production.
The volumes represent Avista specific large users of natural gas. Stochastic variability
was not wide enough to use in the risk portion of the model (Chapter 8) as provided by
ICF for CCUS. Avista will work on determining a reasonable stochastic variability for
CCUS for future planning documents. More work is needed to understand the capturing
of carbon at these large facilities to account for the possibility of additional costs and
resources (pipelines, storage) needed for a full set of costs. For these reasons we have
pushed out CCUS as a resource potential until 2035. Additional description of carbon
capture and all alternative fuels can be found in Appendix 6.
Avista Corp 2025 Natural Gas IRP 164

Chapter 6: Supply-Side Resource Options
Figure 6.22. Options for COz Utilization (via NETL)
fuel. Foos Pharmaceutical 1
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Algae
Carbonaled Beverages map-
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_Sysported Area l Protect Reactive Powders Added to,tilsdiral U:A.Respiralnry Slimulanl
SMeW Gas in Welding Aerosol Can Propellent
Drs Ice Pellet.Used for Sand Blasting
Red Atud Carbonation
Source-National Energy Technology laboratory srwwnetl.doe.gov
Figure 6.23: CCUS Fixed and Variable Priced per Dth (nominal $)
$50
$45
$40
o $35
a $30
tr, $25 �.
$20
$15
o $10
Z $5
$-
W r` O M O r N Mqt In W r,- W M O N M 11 In
N N N N M M M M M M M M M M ' 'I q* q* 'q
O coo O O O O Coco O O O Coco O
N N N N N N N N N N N N N N N N N N N N
—under 25 Dth/hr-Industrial CCUS 25-50 Dth/hr-Industrial CCUS
50-100 Dth/hr-Industrial CCUS 100-200 Dth/hr-Industrial CCUS
200-400 Dth/hr-Industrial CCUS 800-1600 Dth/hr-Industrial CCUS
Direct Air Capture-DAC CCUS
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Chapter 6: Supply-Side Resource Options
Figure 6.24: CCUS Volumes Modeled MTCO2e
2,500
under 25 Dth/hr-Industrial CCUS
25-50 Dth/hr-Industrial CCUS
2,000 _ 50-100 Dth/hr-Industrial CCUS
■ 100-200 Dth/hr-Industrial CCUS +�
(, 1,500 ■200-400 Dth/hr-Industrial CCUS
0 ■ 800-1600 Dth/hr-Industrial CCUS
■ Direct Air Capture-DAC CCUS
g 1,000
500
0
CO f` CO M O r N M Iq Ul W r*- 00 M O N M "I In
N N N N M M M M M M M M M M q* q* Iq "I � �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG Program Considerations
As Avista prepares to move forward with new RNG supplies, some of the primary
considerations given are as follows:
• Evaluate available RNG procurement options.
• Pursue potential RNG development opportunities from local RNG feedstock
resources under new legislation (Washington House Bill 1257 & Oregon Senate
Bill 98).
• Develop an understanding of RNG development cost, cost recovery impacts to
customers, resulting supply volumes and RNG costs.
• Evaluate potential RNG customer market demands vs. supply.
• Participation in RNG rule making and policy determinations, such as:
o Participation in House Bill 1257 Policy development.
o Participation in Senate Bill 98 Policy Rulemaking via OPUC Docket AR 632
informal and formal.
• Cost recovery proposal led by NWGA with input from all four Washington LDC's.
• Collaborative RNG Gas Quality Framework established across four Washington
LDC's.
Utility RNG Projects
Fuel feedstocks are not always readily available nor are feedstock owners who are willing
to partner with an LDC to develop renewable natural gas. Even with potential willing
feedstock partners, Avista recognizes many practical complexities associated with
Avista Corp 2025 Natural Gas IRP 166

Chapter 6: Supply-Side Resource Options
developing RNG projects as well as the many benefits. The following examples are based
on what the Company has learned during its business development efforts;
• Legislation allows LDC's to invest in RNG infrastructure projects with feedstock
partners.
• LDC's are credit worthy partners offering long term off-take contracts to feedstock
owners.
• Each RNG project is unique with respect to capital development costs & resulting
RNG costs.
• Each RNG project will vary in size, location, and distance to interconnection
pipeline, feedstock type, gas conditioning equipment and requirements, and
operating costs.
• Low volume biogas opportunities face economic challenges because of
economies of scale.
• The utility cost of service model is typically a foreign concept to feedstock owners,
requiring an educational process to get them comfortable.
• Feedstock owners over-valuing their biogas can degrade project economics.
• New RNG projects can take three to four years to develop given myriad factors. A
new RNG project is a multi-year endeavor involving the usual phases expected for
major capital construction projects, coupled with many first ever discussions
between the utility and the feedstock owner, a new regulatory process and
program requirements, the identification of customer cost impacts, environmental
benefits, and the tracking process just to name a few.
• Customers have paid for pipeline infrastructure re-usable for a lower carbon
intensive fuel.
Project tvalluation - Build or Buy
Avista recognizes the two primary options to procure RNG; build RNG project(s) or buy
RNG. In the build scenario, new RNG facilities are developed, and the costs are
recovered through the General Rate Case. Avista can also buy RNG from other RNG
producers and pass the costs through the Purchase Gas Adjustment (PGA).
Build
Both Oregon's Senate Bill 98 and Washington's House Bill 1257 are focused on
decarbonization and support the development of new RNG infrastructure and resources
by allowing LDC's to build RNG resources and deliver the RNG. Also, local projects
contribute to improved local air quality and support the local economy during construction
and operations as discussed in Chapter �.
Naturally, feedstock biogas royalties are expected to be a key factor in project economics,
as well as operating costs including power, conditioning equipment type, interconnection
pipeline distance and cost. Since utilities companies are institutional credit worthy
partners with the ability to be a long term off-taker for biogas, it is expected these types
Avista Corp 2025 Natural Gas IRP 167

Chapter 6: Supply-Side Resource Options
of build arrangements will be desirable with feedstock owners, and long-term
arrangements will temper biogas royalty pricing.
Buy
Competition for environmental attributes pits utility companies against the transportation
sector for credits such as the LCFS7 and RIN8 markets. These markets create a cost
competition for producers where selling RNG volumes into these markets can be lucrative
yet risky if markets for these credits move lower than expected.
At Avista, the voluntary RNG program demands will likely have limited volume
requirements and be short-term in nature. Since a short-term, low-volume off-take
purchase scenario is unlikely to be attractive to producers typically seeking long-term off-
take agreements, the expectation is higher RNG costs. Given the nature of this temporary
interim situation, a short-term voluntary pilot program in which off-take volumes may be
procured from a local producer with excess supply, at a negotiated price, may be
advantageous.
This strategy allows Avista to ramp-up and learn more about the demand from its
voluntary RNG program in the near-term, while minimizing risk until the Company can
supply RNG under a longer-term purchase at a lower price.
https://ww2.arb.ca.gov/our-work/programs/low-carbon-fuel-standard
8 https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-
renewable-fuel-standard
Avista Corp 2025 Natural Gas IRP 168

Chapter 6: Supply-Side Resource Options
Environmental Attribute Tracking
Oregon Senate Bill 98 specifies M-RETS9 as the third-party entity designated to manage
environmental attribute tracking and banking for RNG. M-RETS will utilize a proprietary
transparent electronic certificate tracking system where one renewable thermal certificate
(RTC) is equal to one dekatherm (Dth) of RNG. Given the Oregon requirement and in lieu
of contracting with another vendor for the tracking and banking of Washington
environmental attributes, Avista will likely use M-RETS for Washington RNG attributes.
The California RNG market will continue to be a major demand for renewable resources
due to the low carbon fuel standard (LCFS) in addition to the federal Renewable
Identification Number (RIN)10 market. These incentives can drive the value of these
specific renewable resource attributes to many multiples of conventional natural gas
prices. While the market has volatility based on demand, the primary issue of bringing
additional projects into the market is based on the unknowns as it is related to the market
itself. There are currently no forward prices for these renewable credits and the
environmental attribute value for local markets is unidentified. These are some of the
major obstacles potential producers may encounter when looking for financing of their
projects. A potential solution to some of these unknowns in the market is through utility
RNG projects. Feedstock owners would now be able to partner with LDC's to cultivate
new RNG projects. Financing becomes less of an issue as most LDC's are credit worthy
and can provide a measure of certainty with long term offtake agreements.
9 https://www.mrets.org/
10 https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-
renewable-fuel-standard
Avista Corp 2025 Natural Gas IRP 169

Chapter 6: Supply-Side Resource Options
This Page is Intentionally Left Blank
Avista Corp 2025 Natural Gas IRP 170

Chapter 7: Policy Considerations
7. Policy Considerations
Section Highlights:
• The Oregon 2024 Climate Protection Plan is the basis for resource decision making
to serve Oregon customers.
• Washington's Climate Commitment Act's regional cap and trade is the basis for
resource decision making to serve Washington customers.
• Potential tariffs for natural gas purchased from Canada is not considered in this
plan.
Regulatory environments regarding energy topics such as renewable energy, carbon
reduction, carbon intensity, and greenhouse gas regulation continue to evolve since
publication of the last IRP. Current and proposed regulations by federal and state
agencies, coupled with political and legal efforts, have implications for the reduction of
carbon in the natural gas stream. Avista is challenged with trying to balance affordability,
reliability, and the environment with its resource planning solution (Figure 7.1).
Figure 7.1: Resource Planning Balancing Act
ordal ity
Reliability Environment
Avista has always been at the forefront of clean energy and innovation. Founded on clean,
renewable hydro power on the banks of the Spokane river, Avista has maintained an
electric generation portfolio with more than half the generation from renewable resources,
while continuously making investments in new renewable energy, advancing the efficient
use of electricity and natural gas, and driving technology innovation that has enabled and
will continue to become the platform and gateway to a clean energy future.
The evolving and sometimes contradictory nature of environmental regulation from state
and federal perspective creates challenges for resource planning. The IRP cannot add
renewables or reduce emissions in isolation from topics such as system reliability, least
Avista Corp 2025 Natural Gas IRP 171

Chapter 7: Policy Considerations
cost requirements, price mitigation, financial risk management, and meeting changing
environmental requirements. All resource choices have costs and benefits requiring
careful consideration of the utility and customer needs being fulfilled, their location, and
the regulatory and policy environment at the time of procurement.
The lack of a comprehensive federal greenhouse gas policy has encouraged states, such
as California, Oregon, and Washington to develop their own climate change policies and
regulations. The climate policies in Oregon and Washington have added state policies,
impacting the overall trajectory of Avista's resource needs and future rates.
Comprehensive climate change policies can include multiple components, such as
renewable portfolio standards, energy efficiency standards, and emission performance
standards.
Oregon
Oregon's Climate Protection Prr,n,--
The State of Oregon has a history of greenhouse gas emissions and renewable portfolio
standards legislation. For this IRP, the Climate Protection Program (CPP) is the driving
greenhouse gas reduction policy.
In March of 2020, Governor Brown signed Executive Order (EO) 20-04 requiring the
reduction of greenhouse gas emissions to at least 45% below 1990 levels by 2035 and
80 percent below 1990 levels by 2050. EO 20-04 requires statewide reductions by all
carbon emitting sources and managed by the respective emissions sources governing
agencies. State agencies are directed to exercise all authority to achieve GHG emissions
reduction goals expeditiously.
CPP 2021 - The initial CPP was invalidated due to the state's Environmental Quality
Commission not fully complying with disclosure requirements in 2021 when it voted to
create emissions rules that exceed federal rules and affect entities holding industrial air
pollution permits under the federal Clean Air Act.
The CPP is the primary program being used to meet EO 20-04 and is being administered
by the Oregon Department of Environmental Quality (DEQ) under rule DEQ-18-2024,
Chapter 3401. This new version of the CPP was adopted on November 21, 20242, after a
restart of rules process with the rule advisory committee (RAC) in 2024. The CPP is
designed to reduce 50% of emissions by 2035 and a 90% reduction by 2050. Figure 7.2
compares 2021 program rules in 2026 with the 2024 updated rule guidelines. Emissions-
Intensitve and Trade Exposed (EITE) and Direct Natural Gas (DNG) customers are
independently responsible for complying with CPP and may be excluded from the cap
Department of Environmental Quality: Climate Protection Program 2024: Rulemaking at DEQ: State of
Oregon
2 cppFS2024.pdf
Avista Corp 2025 Natural Gas IRP 172

Chapter 7: Policy Considerations
depending on usage above 15,000 MTCO2e3. Avista considers in it's modeling within
the analysis.
,u are 7.2: Oregon Customers Annual Emissions Compliance Cap Comparison
800,000
717,192 — 2021 Avista CPP Cap
700,000 ° — 2025 Avista CPP Cap
600,000
a�
N 500,000
400,000 �� 388,524
300,000
200,000 65,408
100,000
v
L0 (Df` 00 (MO NM 'qL0CDf` 00a) O NM 'qL0 (Df` 00 (MO
N N N N N M M M M M M M M M MNT M* qq NTRI q1 'R* q LO
M O O O M M O O M M M O O O O O O O O O O O O O O O
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
CPP Program Compliance
Oregon DEQ's rules assume a carbon footprint of roughly 117 pounds per MMBtu for
natural gas. For other fuels such as RNG with its renewable thermal credit (RTC) or
obtaining just the RTC is assumed to be a non-emitting source with greenhouse gas
emissions, regardless of its actual emissions intensity profile. The CPP does not include
carbon intensity by source so higher emitting sources such as dairies do not provide
additional emissions benefits over a landfill, as other programs do, e.g. the California
program. Further, RNG/RTCs do not have to be physically sourced in the state of Oregon.
With this provision Avista has greater potential opportunities to seek these resources as
compared to if Avista had to physically deliver the fuel to our system. Another element of
the program is compliance instruments known as Community Climate Investments (CCI).
These instruments allow an entity such as Avista to offset a portion of actual emissions
through the purchase of CCIs. The quantity of CCIs available to Avista is directly related
to the allowed emissions under the CPP as shown in Figure 7.3. In the years 2025 to
2027, the quantity of CCIs available is equal to 15% of the LDC emissions, and 20% for
3 https://ormswd2.synergydcs.com/HPRMWebDrawer/Record/6795229/File/document
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Chapter 7: Policy Considerations
all compliance periods thereafter. Avista may purchase CCls at the nominal prices shown
in Figure 7.4, with an additional adder of 4.5% for DEQ administration.
Figure 7.3: Maximum Available CCI Compared to the Expected Load
700,000
CCI —OR Load
600,000
500,000
a�
04 400,000
U
300,000
200,000
100,000
CC ti CO M O r N M q* 0 0 ti O M O N M R N
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 7.4: Community Climate Investment ($ per MTCO2e)
$180
$160 CCI+4.5% admin fee
a�
$140
p $120
U
$100
(D $80
a
V� $60
$40 E
Z $20
$-
U') W r` CO M O N M Iq LO W r` 00 C7 O N cM qc* LO
N N N N N M CO M M M M M M M M � ICT q1 qt q1 q*
O O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNNN
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Chapter 7: Policy Considerations
Figure 7.5 combines expected emissions from serving load with natural gas as
compared to the number of compliance instruments (CI) given through the CPP to offset
these emissions. The net delta would be where resources are needed to meet Avista's
CPP targets. The resource mix to meet the greenhouse reduction goals of the CPP is
discussed in .,IIdPU:c[ /-. All customers are included in the load estimate where Avista
hold responsibility for compliance.
Figure 7.5: Expected Load Forecast Emissions Compared to CPP Emissions
Target
700,000
600,000 0 CPP Cap OR Load
a�
500,000
N
0 400,000
300,000
200,000
100,000
CD r- co M C N M d LO CD r` CO M C N M19t LO
N N N N M M M M M M M M M eM q1 q1 'q 'q q1 q1
C C C C C C C C C C C C C C C C C C C C
NNNNNNNNNNNNNNNNNNNN
Oregon Senate Bill 33,
Senate Bill 334 was passed in 2017 to develop, update, and maintain the biogas inventory
available to Oregon customers. This includes the sites and potential production quantities
available in addition to the quantity of RNG available for use to reduce greenhouse gas
emissions. This bill also promotes RNG and identifies the barriers and removal of barriers
to develop and utilize RNG. In September 2018 the Oregon Department of Energy issued
the report to the Oregon legislature titled "Biogas and Renewable Natural Gas Inventory.4"
Oregon Senate Bill 84,,
Senate Bill 844 passed in 2013, with OPUC rules going into effect in December 2014.
This bill directed the OPUC to establish a voluntary emission reduction program and
4 2018-RNG-Inventory-Report.pdf
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Chapter 7: Policy Considerations
criteria for the purpose of incentivizing public natural gas utilities to invest in emission
reducing projects providing benefits to their respective customers. The public utility,
without the emission reduction program, would not invest in the project in the ordinary
course of business.
To date, this legislation has not yielded any emission reducing projects. Avista is aware
that Governor Brown's Executive Order 20-04 has the OPUC reconsidering the
usefulness of SB 844.
Oregon Senate Bill 98
Senate Bill 98 was passed during the 2019 regular session and mandates the OPUC "to
adopt by rule a renewable natural gas program for natural gas utilities to recover prudently
incurred qualified investments in meeting certain targets for including renewable natural
gas purchases for distribution to retail natural gas customers."
The OPUC initiated a rulemaking to implement Senate Bill 98 under Docker AR 632 in
late 2019 with final rules taking effect on July 17, 2020. To participate in a SB 98 RNG
Program, a petition to participate is required. Small utilities desiring to participate are
required to define their respective percentage of revenue requirement per year needed
to support potential project investment costs. The bill allows investment in gas
conditioning equipment without RFP process. Per the OPUC's rules, the RNG attributes
will be tracked by the M-RETS system as renewable thermal certificates (RTC) in which
(1) RTC = (1) Dekatherm of RNG.
Washington
Washington State Policy Considerations5
In 2008, Washington's Legislature introduced a framework for reducing greenhouse gas
emissions with HB 28156. In December 2020, Washington State's Energy Strategy was
released as a roadmap to meet Washington's laws of reducing greenhouse gas
emissions, as follows:
• By 2030 a 45% reduction below 1990 levels
• By 2040 a 70% reduction below 1990 levels
• By 2050 a 95% reduction below 1990 levels and net-zero emissions
Climate Commitment Act
The Washington legislature passed into law its largest environmental program in 2021,
the Climate Commitment Act (CCA) (RCW 70A.45.020). The CCA is administered by
Washington Department of Ecology with the program beginning January 1, 2023. The
CCA creates a state-wide emissions cap and invest program where statewide emissions
5 https://www.commerce.wa.gov/growing-the-economy/energy/2021-state-energy-strategy/
6 Washington State Greenhouse Gas Emissions Inventory
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Chapter 7: Policy Considerations
are to be reduced by 95 percent by 2050. The CCA will also expand the air quality
monitoring in overburdened communities with evaluation every two years to ensure
pollutants and greenhouse gases are being reduced. Initial covered entities under the
CCA include industrial facilities, certain fuel suppliers, natural gas distributors, and in state
electricity suppliers. Figure 7.6 illustrates the CCA coverage by percentage of emissions
and industry type for included covered entities.
Figure 7.6: Climate Commitment Act Coverage'
Industrial Refineries
Not covered 3% 6%
25%
■Covered
■Not covered
Other _
1%
Natural Gas Transportation
11% 35%
Electricity
19%
Future emitting participants will be added in 2027, for example the inclusion of the City of
Spokane's Waste-to-Energy plant. The emission allowance cap for the CCA reduces
emissions beginning 2023 by 7 percent annually until 2030. The cap then decreases by
1.8 percent annually from 2031 to 2042. Carbon dioxide emissions from biomass or
biofuels are exempt from this program.$ Finally, the cap decreases by 2.6 percent in the
years 2043 to 2049 to fully meet the 95 percent below 1990 reduction state goal noted
above. For modeling purposes, we fully exclude any emissions from RNG for compliance
with the CCA in the resource selection described in Chapter 2. A summary of the pro rata
share of this reduction to Avista's LDC emissions is shown in Figure 7.7.
All covered entities are required to obtain allowances or offsets to cover their emissions.
Offsets are projects reducing, removing, or avoiding greenhouse gas emissions and are
verified through audits. Offsets can be used in place of allowances beginning in the first
compliance period of 2023 — 2026, with limit of a total of 5% of their emissions from
general offset projects and 3% from Tribally supported projects. These offset projects
include four protocols adopted from the California program and include U.S. Forestry,
Washington State Department of Ecology produced graphic
a RCW 70A.65.080 (1)(iii)(7)(d)
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Chapter 7: Policy Considerations
Urban Forestry, Livestock Projects, and Ozone Depleting Substances. As of December
2024, three projects have been approved for offset credits totaling 310,000 MTCO2e9 of
credits.
Offsets are below the cap meaning allowances and offsets are interchangeable and
should be procured on a least cost or least risk basis. Also, if offsets are used for
compliance, less CCA credits will be available to other participants. These offsets drop
after this initial timeframe to 4% general offsets and 2% of Tribal offsets going forward
starting 2027. Transport customers outside of Avista's obligations have access to the
allowance market. For those transport customers within Avista's compliance obligations,
Avista purchases allowances for all customers, regardless of class, for compliance.
Figure 7.7: Expected Load Forecast Emissions Compared to CCA Emissions
Target
1,400,000
No Cost Allowances
1,200,000 — WA Load
1 ,000,000
c� 800,000
O
600,000
400,000
200,000
CD I� W M O N M I V7 CD f` W M O N M 11 to
N N N N M M M M M M M M M M NI�t 'R* "I 'q
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
Program participants will be required to cover their emissions by the purchase of
"allowances" acquired through state auction or by purchasing offsets in the secondary
market. Electric utilities are also required to offset their emissions but will be given free
allowances to cover most of their emissions. Electric utilities are already covered under
the Clean Energy Transformation Act which requires 100% clean energy by 2045. The
full impacts of the CCA to Avista's customers are not known at this time.
9 Ecology Offset Credit Issuance Table
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Chapter 7: Policy Considerations
The CCA allows for Washington to join California and the Quebec markets to increase
"allowance" liquidity possibly as early as 2026. California and Quebec still need to
approve the addition of Washington to their program.10 The law also focuses on using
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. This plan assumes linkage with California and Quebec to
determine our forecast of emission pricing.
Allowances are available through quarterly auctions or traded on a secondary market.
Allowances will decrease over time to meet goals state statutory limits. All proceeds from
allowances must be used for clean energy transition. This transition includes bill
assistance, clean transportation, and climate resiliency projects promoting climate justice
with a minimum of 35 percent of funds to provide direct benefit to overburdened
communities. Allowances price estimates used for evaluation are illustrated in Figure 7.8
where the floor and ceiling prices are in the dotted black lines.
Figure 7.8: Expected CCA Allowance Prices
$400 Min ——— Percentile: 25%
$350 Mean —— — Median .•
Percentile: 95% — — Max
cai $300 ••'-
O
$250
69� $200 000•'� was
40,
OV
I�
$150 '
,.•,e
.y•z- _— dw Ow
zSaw
•• ,ewe pest — — —— —
OV ro cow
•••..
$50 - so
to r` CO M O N co Iq LO CO r` CO a) O N Mqt* u7
N N N N M M M M M M M M M cM Nt Iq Iq Iq Iq Iq
M O O O O O O O O O O O O O M O O O O O
N N N N N N N N N N N N N N N N N N N N
Washington HB 12!_
HB 1257 was passed during the 2019 Regular Session, coined the "Building Energy
Efficiency" bill, mandating each gas company to offer by tariff a voluntary renewable
natural gas service. The bill also allows LDCs to create an RNG program to supply a
10 Cap-and-Trade Program I California Air Resources Board
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Chapter 7: Policy Considerations
portion of the natural gas it delivers to its customers. Any such program is subject to
review and approval by the WUTC. Regarding natural gas distribution companies, this bill
was designed for the purpose of establishing the following:
"efficiency performance requirements for natural gas distribution companies,
recognizing the significant contribution of natural gas to the state's greenhouse
gas emissions, the role that natural gas plays in heating buildings and powering
equipment within buildings across the state, and the greenhouse gas reduction
benefits associated with substituting renewable natural gas for fossil fuels."
Section 12 of the bill "finds and declares:
a) Renewable natural gas provides benefits to natural gas utility customers and to the
public;
b) The development of RNG resources should be encouraged to support a smooth
transition to a low carbon energy economy in Washington;
c) It is the policy of the state to provide clear and reliable guidelines for gas
companies that opt to supply RNG resources to serve their customers and that
ensure robust ratepayer protections."
Section 13 of the bill allows LDC's to propose an RNG program under which the company
would supply RNG for a portion of the natural gas sold or delivered to its retail customers.
Section 14 of the bill states that LDC's must offer by tariff a voluntary RNG service
available to all customers to replace any portions of the natural gas that would otherwise
be provided by the gas company.
HB 1257 provided limited direction and the necessary details to advance RNG programs
and projects. As such, there has been an effort on behalf of the impacted utilities to
provide the commission with feedback and clarity with respect to gas quality and cost
treatment. More specifically, the Northwest Gas Association (NWGA) has collaborated
with Washington LDC's to develop a common Gas Quality Standard Framework, and
proposed language defining the treatment of RNG program costs.
On December 16, 2020, the Washington UTC issued a Policy Statement to provide
guidance with respect to the following elements of HB 1257 as follows; General Program
Design, RNG Program cost cap, Voluntary Program cost treatment, gas quality
standards, and pipeline safety, environmental attributes and carbon intensity, renewable
thermal credit (RTC) tracking, banking, and verification.
ocial Cast of Greenhouse Gas
Figure 7.9 shows the social cost of greenhouse gas at 2.5%, this price represents the
marginal cost of the impacts caused by carbon emissions per metric ton at any point in
time. This price forecast is used in two specific areas of the 2025 Gas IRP. The first is for
the evaluation of energy efficiency in Washington in the Total Resource Cost test in
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Chapter 7: Policy Considerations
combination of upstream emissions. The second way these costs are incorporated is
through the Social Cost of Greenhouse Gas scenario found in -hapt 'I. In this scenario,
this price is used for Washington's resource decision making. The "SCGHG Nominal $"
is what is employed in this IRP where Social Cost of Carbon is mentioned.
Figure 7.9: Social Cost of Carbon at 2.5% Modeled Costs
$250 SCGHG (2007$) !SCGHG (2022$)
SCGHG Nominal $
$200
0
$150
L
G
$100
0.
$50
$0
tD t` CO M O N M 'Tt LO CO r` CO (M O N M 'q LO
N N N N M M M M M M M M M M � � IRt NtNt Kt
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Initiative 2066
In 2022, Washington's" Building Council passed new commercial and residential
construction building code changes to require heat pumps for space and water heat
beginning July 1, 2023 for new construction. For residential buildings, codes do not
require a specific fuel source if heat pump technology is utilized.
In response to these building code changes, Initiative 2066 was passed into law on
December 5, 2024 and was aimed at a 2024 law that stops a large combination utility,
Puget Sound Energy (PSE), from incentivizing the use of natural gas. This law prevented
PSE from offering any customers a rebate for installing gas-powered appliances. The
initiative reverses these code changes and ultimately written to protect natural gas access
and prohibit state and local governments from discouraging natural gas use. This initiative
allows local utility services to continue to offer gas as an option to customers who request
it.
11 igital Codes (iccsafe.org)
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Chapter 7: Policy Considerations
While those against the measure, No on 1-2066, have conceded the race, they are
exploring possible legal challenges to the measure. The Building Industry Association of
Washington has also filed a lawsuit to declare that the Washington State Building Council
must comply with 1-2066. While the outcome of these legal challenges is unknown, a
higher load forecast is considered through scenario analysis to understand the impact if
the law changes remain and can be found in chapter 8. Due to timing of the initiative
passing and the modeling process, this load forecast is not available for the Preferred
Portfolio Analysis. Oregon and Idaho do not currently have any codes or policies requiring
building electrification.
Thermal Energy Networks (TENs)
TENs provide thermal energy for space heating, cooling or process uses from a central
plant or combined heat and power facility. This thermal energy is distributed to two or
more buildings through a network of pipes. ESHB 213112 authorizes gas and most
electrical companies to own or operate a TENs, subject to oversight from the WUTC.
These networks may be considered depending on the availability of a specific area and
estimated costs to develop and administer the network, subject to WUTC approval.
Federal Legislation
Various federal agencies, including the Consumer Product Safety Commission,
Department of Energy, Department of Housing and Urban Development and
Environmental Protection Agency, have been petitioned to, or are either considering new
regulation of natural gas appliances, or are considering banning the use of fossil fuels in
federal buildings and subsidized public housing. To date, no new regulations from the
federal level have been adopted in this regard.
Inflation Reduction Act
Signed into law in August 2022, the Inflation Reduction Act (IRA) provides support in the
form of grants, loans, rebates, incentives, and other investments for clean energy and
climate action. The IRA includes over $300 billion in available funding and tax credits to
be used for climate and energy programs starting in 2023 to 2032. This program both
extends and expands the renewable electricity production tax credit and the energy tax
credit and provides for a "technology neutral" clean electricity production and investment
credit. Credits range from zero-emissions nuclear power production credit, carbon
capture and storage, clean hydrogen to energy manufacturing credits.
There are bonus credits with projects meeting certain prevailing wage and apprenticeship
requirements with an additional 10 percent credit bonus if produced domestically with
domestic products. The credits discussed below assume direct impact on prices and
technology maturity as discussed in unapter 4.
12 2131-S.E SBR ENET OC 24
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Chapter 7: Policy Considerations
Various tax credits may apply to renewable energy production including wind, geothermal,
solar, RNG, hydropower and all forms of renewable energy for facilities placed into
service after December 25, 2022. Additionally, these facilities must have begun
construction prior to January 1, 2025. This is assumed to impact the overall build of
renewable sources and green hydrogen production and the availability of carbon to react
synthetic methane. Carbon capture technologies include ranges of incentives based on
type.
Direct Carbon Capture Facilities must capture a minimum of 1,000 metric tons of carbon
dioxide during the tax year. The base rate starts at $36 per metric ton with a higher rate
of $180 for carbon dioxide captured for storage in geologic formations. If the carbon is
captured and used by the taxpayer a rate of $26 to $130 per metric ton is applicable. A
final credit is available for carbon captured and used for enhanced oil recovery or other
use but is not included or considered in this IRP.
A credit applies to clean hydrogen production after December 31, 2022, for a facility with
construction beginning before 2033. The credit includes a base of 60 cents per kilogram
and is multiplied by the lifecycle greenhouse emissions rate percentage with a bonus
credit for prevailing wages, domestic materials, and investment. A full credit in the amount
of $3 per kilogram is attainable considering meeting each credit criteria. Avista assumes
this $3 per kilogram in its price forecast for green hydrogen.
Finally, a buildings and end use efficiency credit in the IRA includes incentives for
homeowners' investment in energy efficiency. It includes a tax credit for upgrading end
use equipment including insulation, windows, doors, and end use equipment. We assume
a 50% direct credit to the homeowner for costs to convert from natural gas to electric end
use. All resource options in have incentives from the IRA included in estimated
costs where applicable.
Due to changes in the Federal Administration, Avista is not confident all provisions in the
IRA will remain. Avista will re-evaluate these assumptions in the 2027 IRP as new policy
is enacted.
Tariffs
Avista is not including any effects of potential tariffs from Canadian natural gas within this
plan. Avista purchases approximately 83% of natural gas from Canada. Due to lower
prices of Canadian fuel compared to US sources in the Rockies, there will be minimal
switching between Canadian and US gas basins as Avista's interstate pipeline contracts
from the Rockies supply is limited. Finally, the cost of natural gas commodity ranges
between 20% and 50% of the customer prices, therefore tariffs on imported natural gas
may have a minimal impact on customer rates.
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Chapter 7: Policy Considerations
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Chapter 8: Alternative Scenarios
8. Alternative Scenarios
Section Highlights:
• Future demand remains the most uncertain assumption in this plan.
• Portfolio risk of the PRS is dependent on quantity, availability, and price of
alternative resources.
• Recent peak weather events and diversification of resources are increasingly
important to consider in a future resource mix.
• The system benefits from a local storage and fuels to improve resilience if interstate
pipelines become unavailable.
This chapter identifies the resource portfolios for alternative future assumptions, such as
differing demand and supply resource scenarios as compared to the Preferred Resource
Strategy (PRS). Scenarios consider different underlying assumptions vetted with the
Technical Advisory Committee JAC) members to develop a consensus about the
number and types of cases to model. These scenarios help in the understanding of the
PRS results and provide insights into the costs and benefits of future policy changes.
Alternate Demand Scenarios and Sensitivities
As discussed in "'hapter Avista identifies alternate scenarios for detailed analysis to
capture a range of possible outcomes over the planning horizon. All cases identified as a
scenario (Table 8.1) are studied using 500 Monte Carlo or stochastic simulations to
identify risks and outcomes by various weather, price, and alternative fuel volume
availability. These scenarios may represent a major change with forecasted demand or
policy. Alternative sensitivities (Table 8.2) help in the understanding of how resources
selections may change based on adjustments to expected inputs and use deterministic
assumptions. A guide to these assumptions and how all cases compare to one another
is included in Table 8.3.
Monte Carlo runs are helpful to understand risks for the selected resources based on the
specific changes. When comparing scenarios and sensitivities, a deterministic model is
useful to help show cost variability based on different assumptions. If Avista were to
compare all scenarios and sensitivities, based on statistics, the costs would average out
to roughly those costs as depicted in the deterministic scenarios. For this reason, using
Monte Carlo on all cases evaluated is not helpful as they use the same values. The PRS
is the most reasonable to run a Monte Carlo for risk of differing prices, loads and volumes
available as it is the expected future.
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Chapter 8: Alternative Scenarios
Table 8.1: IRP Scenarios
Scenario Description
Diversified Portfolio Forces alternative fuels on system in 2030 to begin system
decarbonization.
No Climate Programs Assumes less climate programs to help quantify PRS cost
impacts.
Preferred Resource Strategy All expected assumptions and preferred resource selection
based on expectations.
Resiliency An outage occurs over peak day weeks (Feb. 2811 and Dec.
20t") and assumes 50% availability of transport and storage
resources on the west side Sumas, JP as unavailable.
Social Cost of Greenhouse Gas PRS assumptions and resource selection based on Social Cost
of Greenhouse Gas.
Table 8.2: IRP Sensitivities
Sensitivity Description Case Weather PRS assumptions using average 20-year historic weather
and 3- year customer usage coefficients.
High Alternative Fuel Costs Higher than expected costs for alternative fuels using 95th
percentile of prices from all Monte Carlo draws.
High CCA Pricing 95th percentile of all 500 Monte Carlo draws for Climate
Commitment Act CCA prices.
High Growth on Gas System Highest growth scenario for loads with corresponding
increased energy efficiency forecast.
High Natural Gas Prices 95th percentile of all 500 Monte Carlo draws for natural
gas prices.
High Electrification Highest loss of customers due to building electrification
includes corresponding decreased energy efficiency
forecast.
Hybrid Heating Assumes customers add an electric heat pump to their
existingnatural gas furnace over forecast horizon.
Initiative 2066 Adds Washington's new commercial customers usage to
the expected load forecast.
Low Alternative Fuel Costs 5th percentile of all 500 Monte Carlo draws for natural gas
prices.
Low Natural Gas Use Lower than expected demand on the as compared to the
PRS. Also includes the RCP 8.5 weather, high alternative
fuel prices and low volumetric availability. High natural gas
prices. High CCA allowance prices.
RCP 6.5 Weather Assumes RCP 6.5 weather futures rather than RCP 4.5.
RCP 8.5 Weather Assumes RCP 8.5 weather futures rather than RCP 4.5.
No Purchased Allowances After 2030 Assumes no Allowances are purchased after 2030.
No Growth Assumes no new customers after phaseout of gas line
extension subsidies in Washington (2025) and Oregon
(2026).
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Chapter 8: Alternative Scenarios
Table 8.3: Scenario and Sensitivity Input Guide
Natural Alternative Alternative Social
Load Pe ak Gas Allowance Fuel RTC Fuel RTC Carbon Costof
2025 IRP Cases Forecast Days Weather DSM Prices Prices Prices Prices Volumes Volumes Intensity Carbon
PRS Expected None
Hybrid Heating Hybrid Heating
Initiative 2066 Initiative 2066
No Growth No Growth
RCP 6.5 Weather RCP 6.5
RCP8.5 Weather RCP 8.5
r
UPC
Average Case Weather 3-Year No Peak20 Year
Days Average
High Electrification Bectrification Low
Quantities
High Growth on Gas System High Growth High
Quantities
Low Natural Gas Use Case Low Growth Hi Hi H kq h I High 1 Low Low__F
High Natural Gas Prices Hi
High CCA Costs High
High Alternative Fuel Costs HiQh Hi
LowAlternative Fuel Costs Low Low
Upstream SCC
Social Cost of Carbon Emissions Included
Included
Diversified Portfolio Alternative fuelsforced onto system in 2030,40%of CCAand CPP compliance met with Hydrogen(20),RNG(17),and Synthetic
Methane(3).
No Climate Programs CCAa nd CPP programs are removed from consideration
No Purchased No Allowancesare available for purchase after 2030.
Allowances After 2030
Resilienc Sumas,Station2,andJPcapacities firnited to 50%during weekof peakday.
Deterministic Evaluation
A deterministic evaluation was used to consider alternative cases. These alternate
demand and supply scenarios are placed in the model as predicted future conditions for
supply portfolio to satisfy with least cost and least risk resources. This creates bounds for
analyzing the Preferred Resource Selection by creating high and low boundaries for
customer usage, weather, alternative fuels volumetric availability and pricing. Each
portfolio is simulated through CROME where the supply resources, demand resources
and energy efficiency are compared and selected on a least cost basis. Results are not
all directly comparable as different demand and price assumptions change the least cost
results.
Demand
Demand profiles for firm customers, or customers where Avista complies with a climate
program, are net of energy efficiency measures shown in Figure 8.1 illustrate the demand
risks from the alternate scenarios. The demand for our Average case shows the greatest
expected system demand using historic use per customer and weather. The High
Electrification case indicates the lowest expected demand using the end-use modeling
methodology as discussed in Chapter 3. As discussed in previous chapters, demand is
the greatest risk in this IRP and has fundamentally changed due to building codes, clean
energy policies, and lowering expected energy use intensity. These demand forecasts
show a decreasing demand throughout the study horizon. Further analysis will be
necessary to carefully consider the impacts to future demand expectations and resources
to meet those needs.
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Chapter 8: Alternative Scenarios
Figure 8.1: System Annual Demand Scenarios
50
45
40
35 -�
30
0
N 25 —0—PRS + All Others (same load)
s= Average Use
20 High Electrification
—High Growth
15 —Hybrid Heating
FRCP 8.5
1 FRCP 6.5
5 —Social Cost of Carbon
12066
—No Growth
CC r` CO C" C) N M 'RT LO CG r` CO M O CV M NT LO
N N N N M M M M M M M M M M qcT NT 'qqct qcT 'Tt
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Scenario Forecasts
Scenarios include future combinations of inputs to measure implications of alternative
possible outcomes. The scenarios evaluated consider a quantitative approach to look for
the best and worst outcomes of key model inputs. These scenarios consider plausible
futures with critical uncertainties and are useful to determine resource selections to
compare directly with the PRS results. These scenarios are run both deterministically and
through 500 Monte Carlo simulations where a daily selection is made for each year of the
20-year forecast. The results shown in this section are shown in metric tonne equivalents
of greenhouse gas emissions, it includes a forecast for Washington's CCA allowances,
Oregon's CCls, RTCs, Alternative Fuels, demand side options and carbon sequestration
to comply with Washington and Oregon's clean energy policy objectives. Also included in
the total greenhouse gas emissions forecast, this forecast includes the actual emissions
from all states excluding the state policy offsets. The term "CPP Cis", found in each figure
below, are the given compliance instruments from the CPP program and adjust annually
with the cap.
Avista Corp 2025 Natural Gas IRP 188

Chapter 8: Alternative Scenarios
preferred Resource Strategy
The PRS is covered in detail in Chapter 2 and included herein for reference and
comparison to other scenarios and sensitivities below. This scenario is based on
expected future conditions and stochastic modeling as discussed further in this chapter.
In Figure 8.2 the PRS deterministic run is shown for comparative purposes to other
scenarios as discussed below.
rigure 8.2: Preferred Resource Strategy (MTCO2e)
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0
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........... lot
0 O � .
CD
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C G C C C C C C C C G C C C G C C C C C
N N N N N N N N . N N . N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CO
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 189

Chapter 8: Alternative Scenarios
No Climate Programs
This scenario considers a future with no climate programs or clean energy policies. The
intent of this scenario is to use the results to help with cost implications of these programs
in comparison to other scenarios to help estimate total cost impacts. All other inputs and
elements discussed remain the same as the PRS. In the absence of climate programs,
Avista would only procure RTCs from current offtake contracts. These RTCs could be
used for Avista's voluntary RNG program or sold into the RIN and LCFS markets as
discussed in voter 5. All energy acquired is from natural gas, as this fuel is the least
cost option to serve customers. The resulting emissions from this scenario is shown in
Figure 8.3. No offsets or alternative fuels are procured to offset these total natural gas
emissions. Due to the reduction in expected sales, Avista does not assume any additional
pipeline transportation is required to meet future demand.
:figure 8.3: No Climate Programs (MTCO2e)
0.8
0.6
0
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0.2
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N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture i Alternative Fuels
Energy Efficiency O Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 190

Chapter 8: Alternative Scenarios
Social Cost of Greenhouse Gas
This scenario generally assumes the same assumptions as those in the PRS, but uses
SCGHG pricing at the 2.5% discount rate for all resource selections including upstream
emissions for all jurisdictions. This cost is for resource selection only and is not included
in total costs comparisons. The scenario considers this adjustment to all jurisdictions
based on the full emission cost adder from production to customer use. Alternative fuels
selected in year 2045 are nearly 10.5 million Dth and decrease the number of CCls and
allowances needed by 89% and 38%, respectively, when compared to the PRS. CCUS
also declines by 59% of total quantities. Selected resources are shown in Figure 8.4.
Figure 8.4: Social Cost of Greenhouse Gas (MTCO2e)
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O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
iiiiiiii Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 191

Chapter 8: Alternative Scenarios
Diversified Portfolio
In the Diversified Portfolio case, all elements of the PRS's assumptions are used, but in
this case, resources selection is a mix of alternative fuels regardless of a least cost test
for Washington and Oregon. This sensitivity measures the potential costs of requiring
decarbonization to the resource stack through physical fuels rather than other compliance
instruments. RNG is added based on availability by resource occurring across all RNG
production sources at 42% of alternative fuels in year 2030. Synthetic methane is added
across all available production types at 51% of the alternative fuels while the remainder
of the 2030 was hydrogen with 7% of total alternative fuels. Alternative fuels account for
over 13% of total load in 2030. Carbon capture is selected in 2035 while prior contracted
RTCs, Allowances and CCIs round off the resource selections over the forecast horizon
as shown in Figure 8.5.
1=in��ra 8.5: Diversified Portfolio Resource Selection (MTCO2e)
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CD I` 00 O O N emn In Co 1` M M O � N M L.0
N N N N M M M M M M M C) M M � � � � � �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
....... Demand
Avista Corp 2025 Natural Gas IRP 192

Chapter 8: Alternative Scenarios
Resiliency
The Resiliency case assumes 50% availability of Sumas and JP supply points over peak
demand weeks as discussed in Chapter 3. This scenario solves for the least cost resource
mix assuming either pipeline outages, equipment failure such as compressor failures or
pipeline incidents like those experienced in 2018 with the Enbridge pipeline and 2024
Martin Luther King Jr. weekend. Avista tested 30 unique model runs and constraints to
determine alternative methods to optimally serve this load with available resource timing,
however no optimal solutions could be found. To solve this scenario within this IRP, Avista
included a one BCF LNG storage facility in 2026 to allow for a solution without unserved
energy considering new energy storage is not selectable until 2030. Further study on this
scenario is required to determine the most optimal method of preventing unserved load
in the event of this scenario. Avista will further study this scenario for the 2027 IRP.
Resource selections are shown in Figure 8.6 and remain mostly in line with the PRS.
Figure 8.6: Resiliency (MTCO2e)
0.8 -
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c0 r- CO CD � N M � LO cD f- CO (n O N M qt Ln
N N N N M M M M M M M fM fM M It 10 10 qO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 193

Chapter 8: Alternative Scenarios
Sensitivity Forecasts
Sensitivities help illustrate implications of physical impacts to the system, impacts to
program compliance or resource availability. These include outages and expected
volumetric availability of resources such as RNG pose a risk to serving demand as well
as meeting emissions compliance. The following sensitivities show different futures in
comparison to the PRS by changing individual elements like prices, volumetric availability
of fuels, weather, or demand. The results presented here are like the scenarios above
illustrating the portfolio selections in metric ton equivalents to greenhouse gas emissions.
Average Case
The Average Case uses the average daily weather for the past 20 years and a three-year
historical use per customer data for space and heating needs. This scenario assumes the
status quo of customer demand does not change in the future, where demand is not
impacted from significant energy efficiency, weather forecasts, or customer use
decisions. All other assumptions are the same as the PRS, excluding a peak day. Figure
8.7 shows a need for more energy resources to comply with clean energy policies in
comparison to all other futures outcomes discussed in this chapter as energy intensity
per customer does not decline as the PRS assumes. One of the most significant changes
compared to the PRS is Carbon Capture Utilization or Storage (CCUS) increases by over
50%, allowances purchased totaling an additional 17% and CCls increasing by a
staggering 1,400% even with the additional 11% of alternative fuels brought on to the
system. Even with this higher load scenario, Avista does not assume any additional
transportation requirements are needed.
Avista Corp 2025 Natural Gas IRP 194

Chapter 8: Alternative Scenarios
Figure 8.7: Average Case (MTCO2e)
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N N N N M M M M M M M M M M V V 'q 'q "I
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP CIS — CCI
Currently Contracted RTCs RTC
Carbon Capture — Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 195

Chapter 8: Alternative Scenarios
High Alternative Fuel Costs
The High Alternative Fuel Costs case considers alternative fuel costs using the 95th
percentile of 500 pricing simulations. All other inputs are the same as the PRS. The
resource selection, compared to the PRS, shows a 21% decline in total alternative fuels.
To offset this loss, CCI procurements for Oregon double and an additional 16% of
Washington's CCA allowances would need to be purchased. CCUS also increases by
19% to capture emissions from natural gas due to the higher prices to comply with the
standards in Oregon. Figure 8.8 shows the resource selections. Idaho's procurement
strategy does not change.
Figure 8.8: High Alternative Fuel Costs (MTCO2e)
0.8
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0
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0.2
0.0
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0.5 ,
o
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� Natural Gas �Allowances (Free)
Allowances (Given) Allowances (Purchased)
�CPP Cis �CCI
�Currently Contracted RTCs RTC
�Carbon Capture �Alternative Fuels
�Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 196

Chapter 8: Alternative Scenarios
High CCA Allowance Pricing
If higher CCA allowance pricing persists then the PRS's forecast of the resource
selections will change. For this sensitivity, the 95t" percentile of 500 stochastic pricing
simulations (from the PRS) of the forecasted allowance prices is used. All other input
assumptions are the same as the PRS. The impacts, as shown in Figure 8.9, of resource
selections include a 3% drop in the total selection in CCIs and a less than 1% change in
purchased allowances. Increases in CCUS selection of 5% is necessary to offset impacts
of these decreased program instruments. This implies that even at a higher cost,
compliance instruments maintain their overall selections as they continue to offer a least
cost resource in meeting the greenhouse emission reduction requirements.
Figure 8.9: High CCA Allowance Pricing (MTCO2e)
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0.2
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= 0.4 IRK
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N N N N M M M M M M M M M M le V V V V V
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N N N N N N N N N N N N N N N N fV N fV N
� Natural Gas �Allowances (Free)
�Allowances(Given) Allowances (Purchased)
CPP Cis �CCI
Currently Contracted RTCs RTC
Carbon Capture �Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 197

Chapter 8: Alternative Scenarios
High Electrification
This sensitivity considers a loss of system demand due to building electrification, using
an average decline of 4% load loss per year. All remaining assumptions remain consistent
with the PRS. Additional building electrification beyond what is included in this load
forecast is available for the model to further reduce loads to comply with the state's clean
energy policies but are not selected. The resulting resource selections indicate RNG is
selected at 1.15 million Dth, or 56% of the PRS's selection, and CCUS declines by 3%
compared to the PRS by 2045. CCA allowances needed decrease by 53% and no CCIs
are selected as shown in Figure 8.10.
What is not included within these results is the effect to Avista's and other electric utilities
resource needs. These utilities will have higher costs to meet this higher load with
additional generation, transmission, and distribution system enhancements. These costs
are included in the "cost comparison" section below. For example, in Avista's Electric
IRP1, it conducted a Washington building electrification scenario indicating its 2045 winter
peak load would increase by 356 MW, resulting in a rate increase in 2045 from 24.8 c/kWh
to 27.8 c/kWh. This analysis only includes the impact on Avista's service area and not
other utilities where Avista serves gas in their area. Further, this scenario goes beyond
the Electric's IRP's analysis to look at other impacts to the system including Idaho and
Oregon. In this case Avista would have greater impacts due to transmission system
limitations- basically requiring the utility to need up to 475 MW of additional nuclear
generation to cover this load if natural gas generation is not available. Further, Avista
does not serve the Oregon service territory with electric service. This makes it difficult to
estimate the financial impacts to those customers and would need to be analyzed by each
electric provider by planning region to get accurate costs. A forecast was estimated for
these costs based on current rates as used in the electrification estimate described in
unapter - . These results do not consider decreased capacity or distribution costs as the
necessary detail to understand where and when customers electrify is not possible to
model in CROME. Further, these costs could decrease if all customers on a distribution
line electrify but would likely remain if even a single customer was left on the line. For
safety and reliability reasons, Avista would still be required to maintain this distribution
line.
1 https://www.myavista.com/-/media/myavista/content-documents/about-us/our-company/irp-
documents/2025/2025-avista-electric-irp.pdf
Avista Corp 2025 Natural Gas IRP 198

Chapter 8: Alternative Scenarios
Figure 8.10: High Electrification (MTCO2e)
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0
M •
0.2 •
0.0
0.6
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00.3
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N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 199

Chapter 8: Alternative Scenarios
High Growth on the Gas System
Measuring risk includes a higher-than-expected case for customer growth in our natural
gas territories. The overall growth in this case increases by 18% by 2045 as compared to
the PRS resulting from a higher than expected number of customers, leading to an
increase in overall demand. This high growth case maintains the same demand decline,
like most scenarios and sensitivities, and is based on energy efficiency savings and
higher efficiency in end uses. While Oregon and Washington have policies and programs
making this case unlikely, Idaho is experiencing strong growth as discussed in Chap—
. When compared to the PRS, CCUS has a 51% increase in total quantities selected,
and an 11% increase in total CCA allowances purchased. CCIs drastically increase to
nearly 760,000 over the planning horizon where the PRS selects slightly more than
112,000 CCIs. Alternative fuels also increase by 6% to meet this high growth case as
shown in Figure 8.11.
Figure 8.11: High Growth on the Gas System (MTCO2e)
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0.2
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0 0.4
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O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
� Natural Gas Allowances (Free)
�Allowances (Given) Allowances (Purchased)
�CPP Cis • CCI
�Currently Contracted RTCs RTC
�Carbon Capture Alternative Fuels
Energy Efficiency O Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 200

Chapter 8: Alternative Scenarios
Hybrid Heating
The Hybrid case assumes electric heat pumps are added to existing natural gas furnaces.
Effectively the natural gas system provides heating needs during colder temperatures
with non-peak impact to the electric system as the heating source switches to gas when
the outdoor temperature goes below 38 degrees Fahrenheit2. By 2045 the annual energy
forecast is 13% lower than the PRS's forecast. This scenario results in lower demand
overall for Oregon and Washington. Rather than a total loss of these customers like the
previous electrification sensitivity, a customer would remain on the natural gas system.
All other assumptions remain consistent with the PRS. Total CCIs purchased increased
by 26% to cover emissions in place of alternative fuels or CCUS, which decreased by
18% and 12%, respectively, as compared to the PRS. Finally, allowances slightly
decrease by only 6% as primary heating needs would continue to be met by the gas
system. Selected resources are shown in Figure 8.12.
Figure 8.12: Hybrid Heating (MTCO2e)
0.6
0.4
0
L
fQ
a
0.2
0.0
0.6
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N N N N N N N N N N N N N N N N N N N N
Natural Gas �Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis �CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
2 Residential Code Amendments I SBCC
Avista Corp 2025 Natural Gas IRP 201

Chapter 8: Alternative Scenarios
High Natural Gas Prices
For most cases evaluated in this IRP, all of them continue to rely on natural gas as a form
of energy. Evaluating resource selections based on high natural gas prices is evaluated
in this sensitivity. Figure 8.13 shows resource selections based on the 95t" percentile of
500 stochastic simulations to estimate higher natural gas costs. The resulting natural gas
prices are 57% higher in 2030, 104% in 2045. All other inputs are the same as the PRS.
As expected, the number of allowances selected in total has decreased due to an
increase in alternative fuels selected of 34% as compared to the PRS. CCUS selection
decreased by a significant amount with 25% less carbon capture and a slight reduction in
purchased CCA allowances of 2%. Finally, a drastic reduction of 87% for CCls is primarily
based on the large increase in alternative fuels fulfilling both energy and emission
reduction requirements.
Pirlure 8.13: High Natural Gas Prices (MTCO2e)
0.8
0.6
0
0.4
0.2
0.0
0.6
0.5
sue.•
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CD I-- COM O T- N M q In W 1- OD m O T- N M 'q In
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O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency 0 Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 202

Chapter 8: Alternative Scenarios
1-2066
Initiative 2066 considers a future where the building code is changed to allow new
commercial customers to use natural gas for heating in Washington. This initiative passed
in the state's election in November 2024 and the currently being challenged. This
sensitivity does increase the load expectation in Washington for only commercial
customers to reflect historical use per customer rates. There are no changes to residential
usage in this analysis. The impact of load increases the 2045 system demand by 9% as
compared to the PRS. Avista did not use this sensitivity, as the PRS, due to the
certification of the election, was not completed in time to update all the processes for the
PRS specifically for energy efficiency. Also due to the legal challenges of the initiative
and the minimal change to resource acquisition these changes could be completed as a
sensitivity. If this initiative survives legal challenges, changes will be considered in the
2027 IRP. Figure 8.13 shows overall impact with the selection of an additional 16% of
purchased allowances combined with more natural gas purchased to supply this higher
load. All other resource selections stay the same compared to the PRS.
Figure 8.14: 1-2066 (MTCO2e)
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0.s
0
0.4
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0.0
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N N N M N CV N N N N N N N N N CV N N N N
Natural Gas Allowances (Free)
—Allowances(Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
�Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 203

Chapter 8: Alternative Scenarios
_ow Alternative Fuel Costs
This sensitivity considers lower than expected alternative fuel pricing from 500 stochastic
simulations to estimate low natural gas costs using the 25t" percentile of prices by fuel
type. This assumption change reduces prices of alternative fuels by 11%. The resources
selected include an increase of alternative fuels procured over the planning horizon of 3%
and primarily impact Oregon as allowances remain the least cost resource in Washington.
There are no changes in Idaho selections. CCIs decrease by 10% and a similar reduction
in selected quantities of CCUS. These selections are shown in Figure 8.15.
igure 8.15: Low Alternative Fuel Costs (MTCO2e)
0.8
0.6
0
0.4
0.2
0.0
0.6
0.5
0 0.4
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N N N N M M M M M M M M M M V � 'q V 10 V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Natural Gas �Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP CIS �CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 204

Chapter 8: Alternative Scenarios
_ow Natural Gas Use
The low natural gas use case analyzes an alternative warmer weather future using RCP
8.5, higher prices for natural gas and alternative fuels, low availability of alternative fuel
volumes, and high CCA allowance pricing. RCP 8.5 is considered due to less heating
degree days pushing cost per therm to a higher rate to recover base rates of delivering
energy to the customer and higher costs of energy. This scenario creates a near worst
case scenario for natural gas fuel to test whether electrification becomes cost effective.
When compared to the PRS the selections include 6% less CCUS, a higher selection of
alternative fuels of 6% leading to a system total emission decline of 7%, and no building
electrification selections. Although, high natural gas prices drive the selection of
alternative fuels when combining compliance instruments in Washington and create a
higher cost than alternative fuels. No CCls are selected for Oregon based on higher
alternative fuel volumes used to reduce emissions. Resource selections are shown in
Figure 8.16.
Figure 8.16: Low Natural Gas Use (MTCO2e)
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0
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0.2
0.0
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Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 205

Chapter 8: Alternative Scenarios
RCP 6.5 Weather
The RCP 6.5 weather sensitivity considers PRS inputs with a mid-range warmer weather
future (RCP 6.5) as compared to the PRS. Further information on the assumption of this
forecast is found in Chapter 3. RCP 6.5 does not drastically change the total HDDs as
compared to the PRS in the forecast horizon considering this IRP. If Avista were to extend
the forecast to the year 2100, more significant changes would be apparent. Because of
this, the resources selected include a 1% decline in alternative fuels and allowances, and
a 7% reduction of total Ms. All changes are due to a 0.04% reduction in demand over
the planning horizon. These selected resources are shown in Figure 8.17.
Figure 8.17: RCP 6.5 Weather (MTCO2e)
0.8
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A Carbon Capture Alternative Fuels
=Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 206

Chapter 8: Alternative Scenarios
RCP 8.5 Weather
RCP 8.5 is warmer weather sensitivity considers a separate weather scenario to
understand different futures with declining HDDs. This sensitivity uses the RCP 8.5
weather futures and shows resources selected around a decreased demand in a warming
climate. Like RCP 6.5, the changes in the forecast horizon do not overly deviate from
RCP 4.5 by 2050. Further information on the assumption of this forecast is found in
G.apter .:. The selected resources, in comparison to the PRS, include a 3% decrease in
CCUS and alternative fuels. CCls have an overall decrease of 6% while allowances stay
mostly the same with slight percentage decreases of less than 1%. Selected resources
for this sensitivity are shown in Figure 8.18.
Figure 8.18: RCP 8.5 Weather (MTCO2e)
0.s
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Natural Gas Allowances (Free)
Allowances (Given) Allowances (Purchased)
CPP Cis CCI
Currently Contracted RTCs RTC
Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 207

Chapter 8: Alternative Scenarios
No Allowances 2030+
The No Purchased Allowances After 2030 case mirrors the PRS but does not consider
Washington CCA allowances for purchase after 2030. The selected resources, in
comparison to the PRS, include increases of 66% in CCUS and 324% in alternative fuels
primarily as a resource to replace allowances in Washington for CCA compliance. Total
selected CCls increased 1,303% while allowances unsurprisingly decreased by 77% over
the 20 years. Selected resources for this sensitivity are shown in Figure 8.19. This
sensitivity demonstrates the constraints of scarce qualifying fuels and how alternative
compliance mechanisms such as buying allowances or M's will help control compliance
costs when emission reduction may have significant cost increases.
Figure 8.19: No Purchased Allowances After 2030 (MTCO2e)
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Natural Gas Allowances (Free)
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CPP Cis CCI
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Carbon Capture Alternative Fuels
Energy Efficiency 0 Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 208

Chapter 8: Alternative Scenarios
No Growth
The No Growth case assumes no new customers are added to the natural gas system
after 2025 and 2026 in Washington and Oregon, respectively. This assumption aligns
with the phasing out of subsidized gas line hookups in each state. A declining customer
curve results in lower demand and necessitates fewer alternative fuels and compliance
mechanisms in aggregate when compared to the PRS. By 2045, selected CCls decrease
by 31%, purchased allowances decrease by 14%, CCUS decreases by 26% and
alternative fuels decrease by 23% as shown in Figure 8.20.
.1gure 8.20: No Growth (MTCO2e)
0.8
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Carbon Capture Alternative Fuels
Energy Efficiency o Emissions
......• Demand
Avista Corp 2025 Natural Gas IRP 209

Chapter 8: Alternative Scenarios
Washington Climate Commitment Act Allowances
Comparison of the total purchased allowances across scenarios and the consideration of
availability needs to be carefully examined. As mentioned in Chapter 7, Washington is
currently investigating linkage with the California and Quebec cap and trade program. In
the event Washington does join this program a higher likelihood of sufficient quantities of
allowances will enable the strategy to offset Washington emissions with program
instruments. This remains a risk and will be carefully considered in an ongoing basis to
ensure the risk of non-compliance does not occur.
The Average Case has the highest requirement for allowances through 2045 followed by
the High Growth Case, while the High Electrification scenario has the lowest total
allowances purchased (excludes the "No Climate Programs" scenario. The average total
quantity, across all cases, of allowances purchased across the forecast horizon is just
over 11 million allowances. The variability of purchased allowances by case is illustrated
in Figure 8.21.
Figure 8.21: Annual Allowance Demand by Case — Washington CCA
N 1.250.000
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0 750.000 i
a 500.000
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—Hybrid Heating Diversified Portfolio
Social Cost of Carbon Resiliency
FRCP 8.5 FRCP 6.5
�No Climate Programs —Low Alt Fuel Costs
High Alt Fuel Costs 12066
—High Natural Gas Prices High CCA Allowance Pricing
—0—PRS Average Case
High Growth High Electrification
Low LDC Use Case PRS -MC Open
—No Allowances 2030+ No Growth
Oregon's Community Climate Investments
Community Climate Investments show a greater range of required quantities for
compliance. In Figure 8.22 illustrates the total CCIs purchased for the 20-year forecast
horizon. No Climate Programs, High Electrification and Low LDC Use Case all select zero
CCIs over the time horizon. The "No Allowances after 2030" case selects the highest
Avista Corp 2025 Natural Gas IRP 210

Chapter 8: Alternative Scenarios
number of CCIs with over 1.57 million instruments and illustrates the implications to
Oregon of this consideration. The "Average Case" selects the second most CCIs in total
at just under 1.57 million instruments. The average selection across all scenarios and
sensitivities of 266,000 CCIs.
Figure 8.22: CCI Demand by Case — Oregon CPP
1 .8
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Cost Comparison
When considering the costs of these scenarios and sensitivities, there are three with a
lower cost than the PRS. These cases include RCP 6.5 and RCP 8.5 where weather is
trending warmer and creating less demand to serve, and No Climate Programs. All other
cases have a higher cost deterministically than the PRS. Levelized costs help to depict
an average cost per year over the planning horizon and remove weather volatility. Figure
8.25 shows these levelized costs and includes Avista's discount rate to show a form of a
weather normalized annual payment. The total system costs are shown in Figure 8.23
and compare the 20-year cost, present valued to 2026 dollars, for each scenario. The
Average Case costs are higher than the PRS as it only considers 20-year historic weather
by area and a three-year use per customer. The Low LDC Use Case has a lower demand
from RCP 8.5 combined with much higher costs of natural gas, alternative fuels, and
allowances. The Hybrid scenario is the second most expensive case and includes
calculations for estimated electric side additions of generation, transmission, and
distribution to handle this increased overall load. Finally, the High Electrification case is
130% higher in total costs as compared to the Hybrid case or 580% more expensive as
Avista Corp 2025 Natural Gas IRP 211

Chapter 8: Alternative Scenarios
compared to the PRS and includes estimates for electric generation, transmission and
distribution. Figure 8.24 shows total costs per case across the 20-year planning horizon.
Agure 8.23: PRS Alternative Scenario Cost Comparison
Annual Levelized Costs
$700
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} $500
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$300
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U $100
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Figure 8.24: All Scenarios and Sensitivities 20-Year Costs (2026$)
Z; $16
N $14
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Avista Corp 2025 Natural Gas IRP 212

Chapter 8: Alternative Scenarios
The estimated price impact by scenario by generic class and area are included in Figures
8.4 to 8.7. These figures show the implications of each case in respect to commodity and
supply costs and exclude base and other tariffs. For electrification scenarios, these costs
do not include the impacts to the electric utility.
Table 8.4: Residential Customer Price Impact ($ per dekatherm)
OregonIdaho . .
2045ML Case 2026 2035
2045
Average Case Weather 3.86 5.02 6.92 5.28 9.20 12.33 4.74 8.31 11.28
Diversified Portfolio 3.94 5.10 6.96 5.00 11.34 15.20 4.71 10.02 12.14
High Alternative Fuel Costs 3.94 5.09 6.96 5.01 9.20 11.83 4.71 8.00 10.84
High CCA Costs 3.94 5.09 6.96 5.01 8.94 11.21 4.97 8.83 12.48
High Electrification 3.98 18.70 247.53 5.01 8.41 12.92 4.73 25.38 412.04
High Growth on Gas System 3.90 5.03 6.87 4.79 9.15 12.51 4.70 8.07 10.98
High Natural Gas Prices 4.43 9.05 13.38 5.52 11.51 13.52 5.25 11.86 16.96
Hybrid Heating 3.94 10.84 21.73 5.01 8.35 11.31 4.71 12.28 34.30
Initiative 2066 3.94 5.09 6.96 5.01 8.58 11.36 4.71 8.10 10.98
Low Alte rn ative Fuel Costs 3.94 5.09 6.96 5.01 8.25 11.08 4.71 8.00 10.85
Low Natural Gas Use Case 4.45 9.17 13.31 5.58 12.04 14.48 5.51 12.85 18.57
No Allowances 2030+ 3.94 5.09 6.96 5.01 10.66 13.80 4.71 11.90 13.66
No Climate Programs 3.94 5.09 6.96 4.98 6.65 8.22 3.84 5.25 6.93
No Growth 3.94 5.09 6.96 5.01 8.58 10.14 4.71 7.88 10.63
PRS 3.94 5.09 6.96 5.01 8.71 11.47 4.71 8.00 10.84
RCP 6.5 3.94 5.10 6.96 5.01 8.45 11.07 4.71 8.00 10.83
RCP 8.5 3.94 5.09 6.96 5.01 8.57 11.28 4.71 8.00 10.87
Resiliency 4.81 6.08 7.92 15.01 1 8.58 111.46 15.71 1 8.86 11.21
Social Cost of Carbon 3.94 5.11 6.92 15.00 1 9.64 112.66 14.71 1 9.93 11 .70
Table 8.5: Commercial Customer Price Impact ($ per dekatherm)
OregonIdaho
Case 2026 2035 2045i 0. 2045
Average Case Weather 3.99 5.08 7.00 4.86 8.64 11.43 4.92 8.60 11.81
Diversified Portfolio 4.17 5.21 7.07 4.65 10.48 13.97 5.07 10.30 13.27
High Alternative Fuel Costs 4.17 5.21 7.07 4.66 8.51 10.67 5.07 8.85 12.39
High CCA Costs 4.17 5.21 7.07 4.67 8.25 10.08 5.35 9.88 14.45
High Electrification 4.22 18.65 243.43 4.66 7.55 7.93 5.10 25.99 404.09
High Growth on Gas System 4.14 5.15 6.98 4.42 8.61 11.73 5.06 8.89 12.51
High Natural Gas Prices 4.68 9.25 13.44 5.19 10.89 12.26 5.61 12.77 18.81
Hybrid Heating 4.17 12.34 25.91 4.66 7.66 10.22 5.07 14.17 43.00
Initiative 2066 4.17 5.21 7.07 4.66 7.87 10.30 5.07 8.83 12.23
Low Alte rn ative Fuel Costs 4.17 5.21 7.07 4.66 7.66 10.02 5.07 8.85 12.38
Low Natural Gas Use Case 4.74 9.48 13.53 5.23 11.44 13.21 5.89 13.86 20.84
No Allowances 2030+ 4.17 5.21 7.07 4.66 9.65 12.37 5.07 11.71 13.75
No Climate Programs 4.17 5.21 7.07 4.64 6.05 7.15 4.13 5.52 7.37
No Growth 4.17 5.21 7.07 4.67 7.96 8.91 5.07 8.89 12.52
PRS 4.17 5.21 7.07 4.66 8.11 10.26 5.07 8.85 12.40
RCP 6.5 4.17 5.21 7.07 4.67 7.78 9.88 5.07 8.85 12.40
RCP 8.5 4.17 5.21 7.08 4.67 7.95 10.20 5.07 8.85 12.42
Resiliency 5.06 6.24 8.03 4.67 7.95 10.33 6.15 9.71 12.79
Social Cost of Carbon 4.17 5.22 7.04 4.65 8.73 11.01 5.07 9.79 11.84
Avista Corp 2025 Natural Gas IRP 213

Chapter 8: Alternative Scenarios
Table 8.6: Industrial Customer Price Impact ($ per dekatherm)
OregonIdaho . .
2045 2026 2035 20450•
Average Case Weather 4.20 5.24 7.14 6.41 10.21 11.86 5.60 10.13 14.23
Diversified Portfolio 4.76 5.68 7.53 7.44 12.33 13.83 5.96 10.89 15.55
High Alternative Fuel Costs 4.76 5.67 7.53 7.47 10.84 11.27 5.96 10.86 15.58
High CCA Costs 4.76 5.67 7.53 7.46 10.56 10.39 6.30 12.40 18.60
High Electrification 4.81 15.42 1 56.44 7.47 1 9.53 12.00 1 5.99 21.91 80.17
High Growth on Gas System 4.71 5.56 7.34 7.04 10.43 12.27 5.96 10.90 15.56
High Natural Gas Prices 5.30 9.91 13.72 8.06 12.84 11.98 6.48 14.93 22.70
Hybrid Heating 4.76 12.42 23.44 7.48 9.68 11.32 5.96 16.13 42.53
Initiative 2066 4.76 5.67 7.53 7.48 9.78 10.63 5.96 1 10.69 14.84
Low Alternative Fuel Costs 4.76 5.68 7.53 17.49 9.78 1 10.27 5.96 10.86 15.55
Low Natural Gas Use Case 5.41 10.29 14.07 8.15 13.37 13.04 6.84 16.57 26.34
No Allowances 2030+ 4.76 5.67 7.53 7.47 11.30 13.39 5.96 10.88 13.62
No Climate Programs 4.76 5.67 7.53 7.47 7.95 7.91 4.80 6.00 8.05
No Growth 4.76 5.67 7.53 7.49 10.04 9.22 5.97 110.98 16.03
PRS 4.76 5.67 7.53 7.47 9.92 10.66 5.96 10.86 15.60
RCP 6.5 4.76 5.68 7.53 7.47 9.58 9.95 5.96 10.85 15.60
RCP 8.5 4.76 5.68 7.53 7.47 9.90 10.42 5.96 10.85 15.60
Resiliency 5.71 6.82 8.48 7. 110.50 10.71 7.25 11.72 16.09
Social Cost of Carbon 4.76 5.69 7.51 17.45 1 9.54 1 9.23 5.96 1 9.17 11 .86
Table 8.7: Transport Only Customer Price Impact ($ per dekatherm)
&MMLCaa� 202 - Oregon Washington
IL2045 2026 2035 2045
Average Case Weather 3.17 7.56 11 .30 3.50 6.78 9.64
Diversified Portfolio 2.57 7.04 10.64 3.52 6.78 9.66
High Alternative Fuel Costs 2.57 6.48 10.12 3.52 6.78 9.65
High CCA Costs 2.57 6.34 9.69 3.75 7.84 11.49
High Electrification 2.57 4.72 4.49 3.52 1 6.77 11 .17
High Growth on Gas System 2.38 7.15 11 .36 3.50 6.78 9.65
High Natural Gas Prices 3.11 8.84 15.36 4.13 10.17 15.38
Hybrid Heating 2.57 6.21 9.00 3.52 6.78 9.64
Initiative 2066 2.57 6.35 9.84 3.51 6.78 9.65
Low Alternative Fuel Costs 2.57 6.32 9.89 3.52 1 6.78 9.65
Low Natural Gas Use Case 3.11 9.13 15.35 4.37 11.23 17.23
No Allowances 2030+ 2.57 6.86 13.18 3.52 9.72 11 .73
No Climate Programs 2.57 1 3.48 4.93 2.69 3.63 5.03
No Growth 2.57 5.91 8.76 3.52 6.78 9.65
PRS 2.57 6.35 9.84 3.52 6.78 9.65
RCP 6.5 2.57 6.32 9.78 3.52 6.78 9.65
RCP 8.5 2.57 6.30 9.70 3.52 6.78 9.65
Resiliency 2.57 6.35 9.84 3.51 6.78 9.64
Social Cost of Carbon 12.57 1 6.19 1 9.74 13.52 1 6.79 1 9.66
Avista Corp 2025 Natural Gas IRP 214

Chapter 8: Alternative Scenarios
Finally, to understand cost risks for residential customers, a full rate has been estimated
by scenario as shown in Table 8.8. These costs include current base rates, grown by
inflation through 2045, and are added to the estimated costs per dekatherm as described
above to show a total estimate of customer impacts. Some things to note are the spiraling
of rates in the high electrification scenario and Hybrid Heating scenario. These costs
assume base rates would not be spread by some other instrument such as accelerated
depreciation of the assets in the near term to pay down costs more quickly or some other
combination like spreading these rates through power costs. In the event customers begin
to see these higher rates it is plausible that customers would look to convert their end use
equipment over to electric.
Tah'e 8.8: Est'm-+^d P-P'^"+ ' r, P--+ Impact ($per Therm)
m � -
Average Case Weather 1.04 1.27 1.61 1.56 2.20 2.84 1.38 2.02 2.80
Diversified Portfolio 1.05 1.28 1.62 1.53 2.41 3.13 1.37 2.19 2.88
High Alternative Fuel Costs 1.05 1.28 1.62 1.53 2.20 2.79 1.37 1.99 2.75
High CCA Costs 1.05 1.28 1.62 1.53 2.17 2.73 1.40 2.07 2.92
High Electrification 1.05 2.95 28.75 1.53 2.62 9.25 1.38 4.31 48.85
High Growth on Gas System 1.01 1.20 1.49 1.47 2.00 2.45 1.36 1.94 2.56
High Natural Gas Prices 1.10 1.68 2.26 1.58 2.43 2.96 1.43 2.38 3.37
Hybrid Heating 1.05 2.00 1 3.49 1.53 1 2.16 2.95 1.37 1 2.54 5.75
Initiative 2066 1.05 1.28 1.62 1.53 2.14 2.75 1.37 2.00 2.77
Low Alternative Fuel Costs 1.05 1.28 1.62 1.53 2.10 2.72 1.37 1.99 2.75
Low Natural Gas Use Case 1.10 1.75 2.45 1.61 2.51 3.16 1.46 2.48 3.51
No Allowances 2030+ 1.05 1.28 1.62 1.53 2.34 2.99 1.37 2.38 3.04
No Climate Programs 1.05 1.28 1 1.62 1.53 1 1.94 2.43 1.29 1 1.71 2.36
No Growth 1.05 1.28 1.62 1.53 2.22 2.84 1.37 2.01 2.82
PRS 1.05 1.28 1.62 1.53 2.15 2.76 1.37 1.99 2.75
RCP 6.5 1.05 1.28 1.62 1.53 2.12 2.72 1.37 1.99 2.75
RCP 8.5 1.05 1.28 1.62 1.53 2.13 2.74 1.37 1.99 2.76
Resiliency 1.14 1 1.38 1 1.71 1 1.53 1 2.14 1 2.76 1.47 1 2.08 2.79
Social Cost of Carbon 1 1.05 1 1.28 1 1.61 1 1.53 1 2.24 1 2.88 1 1.37 1 2.18 2.84
Monte Carlo Risk Analysis
Avista employed Monte Carlo risk analysis for estimating probability distributions of
potential outcomes by allowing for random variation in natural and renewable gas prices,
allowance prices, and weather based on fluctuations in historical data. This statistical
analysis, in conjunction with the deterministic analysis, enabled statistical quantification
of risk from reliability and cost perspectives related to resource portfolios under varying
price and weather conditions. Figures 8.25 to 8.30 show the annual costs and frequency
of these costs along with statistics of the 500 draws for each scenario. Figure 8.38 shows
all scenarios run through a Monte Carlo analysis and compare costs and frequency of the
results.
Avista Corp 2025 Natural Gas IRP 215

Chapter 8: Alternative Scenarios
Figure 8.25: PRS - Millions (500 Draws)
60
Average: $293
50 M i n: $235
M ax: $373
40 Median: $291
c 5 t h °/a $261
CD
30 95th °/a $330
Std. Dev.: $20.4
20
10
Ln o Ln o Ln o Ln o Ln o Ln c Ln o Ln o Ln c Ln o Ln o Ln o un
fN CV CV CN CV CV CN CV CV CN N CV N C`7 C`7 C`I n n n n n n n M n
dg dg dg dg dg dg dg dg dg dl!� dg dg d4 dg dg dg Eft dg bg H4 6R. Edg 6F4 Ef3 dg
Figure 8.26: Diversified Portfolio - Millions (500 Draws)
60
Average: $329
50 Min: $275
Max: $401
40 Median: $327
5 t h °/a $302
30 95th °/a $360
r. Std. Dev.: $18.2
U- 20
10
LO o Ln o Ln o LO o Ln o Ln o U1 o Un o Un o U1 o Ln o Ln
r` W W M M O O r r N N n Mq* q LO In W W r` r~ M W
N N N N N M M M M M M M M M M M M M M M M M M
EiT Ei} EH EiT Ei> U). Ef? Vi ffT Ef? EA ff). EiT EA EH EiT VA ER ff? Ef? ER VA Vi
Avista Corp 2025 Natural Gas IRP 216

Chapter 8: Alternative Scenarios
Figure 8.27: No Climate Programs — Millions (500 Draws)
70
Average: $223
60 Min: $174
Max: $299
50 a Median: $222
U 40 5th %: $196
95th °/a $255
30 ills Std. Dev.: $18.1
u_
20
10
M 00 M 00 M 00 M 00 M 00 M 00 M 00 M 00 M 00 M CO M 00 M
f` r` 0 0 0 0 0 O N N M MR* IR* LO LO C,0 CO r` r` 0
T- T" T" T- N N N N N N N N N N N N N N N N N
6A 69 6F3 60 Eg 6F} 6R to Vlt 69 to Vlt to 69 to 60 Eg (F)- 6R 6R (F} 6R 6R
Figure 8.28: Resiliency — 1,000 of$ (500 Draws)
70
Average: $316
60 Min: $260
50 M ax: $396
Median: $315
c 40 5 t h °/d $285
95th °/a $354
30 Std. Dev.: $20.2
20
10
0
W) CO (.Or` r` 00000) M00 CNCNMM � IrtInln0000r` r`
(N (N (N (N (N (N (N (N (N M M CM CM M M CM M M M M M M M M CO
6q 6c} 6c} 6c} 6c} 6c} 6c} 6c} 6c} 6c} 6c} 66- V) 6R 66- 66- 66- 66- VF 61)- 6R 69} 6R 66- 66-
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Chapter 8: Alternative Scenarios
Figure 8.29: Social Cost of Carbon — $ Millions (500 Draws)
70
Average: $317
60 Min: $258
Max: $380
50 Median: $317
jr
5th %: $289
U
40 95th %: $348
30 ob
Std. Dev.: $17.9
Ui
20 - job
10
r` N r` N ti N r` N ti N ti N r` N r~ N ti N r~ N r~ N f`
LO CD t0 r` r` ao W M M O O T- T- N N M M IqIR* LO LO cfl CO
N N N N N N N N N M M M M M M M M M M M M M M
6e} 6Fy bq 6R Vg bq V� Vg bq 611� Vg 611)- V). 6g 641)- 611� V� 6g 64y yg 601)- 64)-
Figure 8.30: Scenario - Monte Carlo Results Comparison - $ Millions
80
PRS me--No Climate Programs
70 Social Cost of Carbon Diversified Portfolio
60
Resiliency
1
U 50
40
a�
�i 30
20
10
0 CO CO M co CO M M M M M M M M M M M M M M M M M M
r` oo a) O T- N M q Lo (.6 r` co a) O N M q Lr) tp r` co cn
T- T" N N N N N N N N N N M M M M M CO CO M M M
6R 6113 611} 611} 611} 60 60 VF 6R 6F} 60 60 VF 6F} 6F} 601f 6q VF 6R 6R 64). to VF
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Chapter 8: Alternative Scenarios
Portfolio Selection
Understanding risk and least cost resources to meet customer demand and state climate
programs requires further analysis of the PRS. All alternative portfolios utilize the same
stochastic inputs in these Monte Carlo simulations allowing a user to appropriately
compare results. Avista used the following methodology to compare risks:
1. Consider resources selected in these cases to identify availability and cost risks
including potential impacts to our customers.
2. Consider policy risks and the likelihood of a future like the "No Climate Programs"
scenario.
3. Utilize all alternative scenarios from the 500 draws (2026-2045) to estimate risk and
costs of each portfolio.
4. Include an additional Monte Carlo simulation, named "Optimized Portfolio", for the
PRS where each individual 20-year draw can select the least cost resource daily. This
occurs across all 500 draws. This general methodology can be compared to a
deterministic analysis running 500 times. These results are shown in Figure 8.31.
5. Compare all scenarios against these levelized costs and risk (standard deviation of
costs) in year 2045.
6. Select the least cost and risk scenario based on results. (Figure 8.32)
rigure 8.31: Optimized Portfolio — $ Millions (500 Draws)
60
Average: $292
50 Min: $236
Max: $373
40 Median: $290
5 t h °/a $261
30 95th °/a $330
Std. Dev.: $20.6
20
�I
10
Mq1IqU1 W) CDCDr` r` WWMMOOT— T— NNMM � qctLOLO
N N N N N N N N N N N N N M M M M M M M M M M M M
69} 69Y 69} VF VF 661 VF 6H 60:Y 69>6FH 6FY 6FY 66- 60}6F3 V). V). 6H 6H 69> 69> 60:Y 6FY 6FY
Avista Corp 2025 Natural Gas IRP 219

Chapter 8: Alternative Scenarios
There are tradeoffs between risk and cost in an approach similar to finding an optimal mix
of risk and return in an investment portfolio, like the efficient frontier 3; as potential returns
increase, so do risks. Conversely, reducing risk generally increases overall cost. Figure
8.32 presents the change in cost and risk from these five different portfolios. Lower gas
cost variability comes from investments in more expensive, but less risky, resources such
as RNG and CCUS.
The "No Climate Programs" is not considered as the PRS based on voter approval to
keep the CCA program. Also, the CPP was passed in November of 2024 so this scenario
and results should be used for cost comparison only for greenhouse gas emissions
programs. The results show an average annual levelized cost reduction of $69 million
dollars as compared to the PRS.
The Social cost of carbon has a higher average annual cost of $24 million dollars as
compared to the PRS, yet only reduces cost risk in 2045 by $15 million. Residential rate
impacts per therm between 2026 and 2035 estimate increases of 46% in Oregon and
59% in Washington.
The "Diversified Portfolio" costs an additional $36 million dollars per year as the PRS, yet
only reduces risk by $9 million dollars in 2045 as compared to the PRS. With a large
number of resources added in 2030 this leads to residential customers in Oregon and
Washington experiencing a 58% and 60% increase, respectively, by 2035. In comparison
to the PRS, where rates are less dramatic and show a rate increase of 41% in Oregon
and 45% in Washington between 2026 and 2035. For these reasons this portfolio was not
considered as a preferred resource.
"Resiliency", as discussed above may not fully consider all cost reductions and risk
reduction benefits of on system storage and will be refined in the 2027 IRP. The results
of the Resiliency scenario show an average annual cost impact of $24 million, yet only a
reduction to the 2045 cost risk of$2 million.
This leaves the "Optimized Portfolio (PRS)" and the "PRS" risks for comparison as they
are both relatively the levelized costs, $292 million and $293 million respectively, but the
PRS has a lower level of risk in 2045 by $2 million. With the lowest cost and risk
combination, the PRS portfolio is selected. Resource acquisition and market availability
of the selected resources of an RFP may alter resources when considering actual costs.
3 Efficient Frontier: What It Is and How Investors Use It
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Chapter 8: Alternative Scenarios
Figure 8.32: Annual Levelized Costs and Risks - All Portfolios
$100
$90 Optimized Portfolio (PRS) Resiliency
°_ $80
$70 No Climate PRS
� $60 Programs SCC
0
$50 Diversified
o $40 Portfolio
o $30
$20
$10
$-
0 0 0 0 0 0 0
Ln o U") o LO o LO
64 6R T- T- CV N M M
6F} 6R 6R 6R 6R 6F}
Annual Average Levelized Cost (Millions)
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Chapter 8: Alternative Scenarios
This Page is Intentionally Left Blank
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Chapter 9: Customer Equity and Metrics
9. Customer Equity and Metrics
Section Highlights:
• Non energy impacts such as social cost of greenhouse gases, upstream
emissions, safety and direct air emissions are considered in resource selection for
fuels in Washington and Oregon.
• Today the use of natural gas is the lowest cost to heat residential homes.
• 19% of Oregon and 18% of Washington Customers are expected to be energy
burdened in 2026.
• Economic impacts were estimated for induced spend for RNG projects and EE.
In recent years, energy equity has emerged as a critical consideration for electric and
natural gas utilities, reflecting a growing recognition of the need to address the diverse
needs of all communities, particularly those historically underserved or vulnerable to
energy-related inequities. Illustrating Avista's Commitment to infusing equity into
operations as directed by both Washington and Oregon Commissions, this chapter
explores the proactive steps taken by Avista to consider and integrate energy equity into
the IRP processes and demonstrating metrics to measure change. By implementing a
comprehensive strategy encompassing community engagement, equitable resource
access, environmental concerns, and continuous evaluation, Avista is setting the
foundation for ensuring natural gas operations are done in a socially responsible manner.
This chapter applies to analysis for Washington and Oregon service territories only,
limited information will be provided for Idaho customers in this section due to its policy
objectives.
Understanding Energy Justice
Energy justice refers to the "goal of achieving equity in both the social and economic
participation in the energy system, while also remediating social, economic and health
burdens on marginalized communities. Energy justice explicitly centers the concerns of
frontline communities and aims to make energy more accessible, affordable and
demographically managed for all communities"' Consideration for energy justice creates
a broader consideration for benefit types, increase input of interested parties regarding
equity issues, and promote continuous process for resource evaluations and the overall
delivery of the energy system within the traditional planning process. To ensure Avista is
effectively planning for equitable outcomes, the four tenets of energyjustice— recognition,
procedural, distributive and restorative — are considered in the natural gas IRP.
Shalanda Baker, Subin DeVar, and Shiva Prakash,"The Energy Justice Workbook" (Boston, MA: Initiative
for Energy Justice, December 2019),
https://iemusa.org/wp-content/uploads/2019/12/The-Energy-Justice-Workbook-2019-web.pdf.
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Chapter 9: Customer Equity and Metrics
Recognition Justice
Recognition justice primarily focuses on whose energy service has been, or is currently,
impacted in a disproportional manner. It is primarily concerned with the historical context
and seeks to understand how previous actions or policies have resulted in disproportional
outcomes. This "... requires an understanding of historic and ongoing inequalities and
prescribes efforts that seek to reconcile these inequalities". Unlike Avista's electric
business which is required to incorporate equity through the Clean Energy Transformation
Act, the natural gas business has not been required to formally identify Named
Communities. Understanding recognition justice sets the foundation for procedural
justice, distributive justice and ultimately restorative justice, several steps were recently
taken to identify those equity determinants such as unemployment, age or education level
that commonly result in energy-related inequities.
Initially, the Company built upon its Washington Named Communities map, based on the
Washington State's Department of Health Environmental Disparities Map by expanding
the electric map to include information on communities served by natural gas.
"disadvantaged" from the White house's Justice 40 initiative map. Through this map the
Company can identify community burdens in the areas of climate change, energy, health,
housing, legacy pollution, transportation, water and wastewater, and workforce
development. These maps provide insight into the identification of communities who may
have, or continue to, receive a disproportionate benefit or burden. For the purposes of
this IRP, these communities identified to be susceptible to energy related inequities will
be referred to as "Named Communities".
Beyond a contextual understanding of disparities, recognition justice also validates lived
experiences, encourages constructive dialogue regarding methods for addressing
inequities, and ensures new policies do not exacerbate existing situations or create
unintended consequences. The Equity Advisory Group (EAG) was established in 2021 to
support these efforts. While initially limited only to characteristics specific to electric
operations, this lens was broadened to represent any customers with characteristics or
circumstances that may lead to inequities in process or disparities in energy access or
affordability. The EAG members have been instrumental in validating inequalities in
known electric Named Community areas and identifying additional communities or
individuals who have or are experiencing disparities within Avista's Washington service
territory.
In addition, Avista is taking the necessary steps to ensure inclusive, diverse
representation through the establishment of an Oregon Equity Advisory group. This group
is currently under development and kicks off initial meetings in early 2025. The Company
will consider additional input regarding socioeconomic or demographics contributing to
energy inequities in Oregon from this group.
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Chapter 9: Customer Equity and Metrics
Although the preferred resource strategy does not directly include consideration for these
communities, the very act of actively seeking out an understanding of where and why
there are disparities sets a solid foundation from which Avista may grow its future planning
efforts.
Procedural Justice
Procedural justice focuses on impartial, accessible, and inclusive decision-making.
Incorporating procedural justice into the IRP process involves ensuring all interested
parties, especially those from Named Communities, have meaningful opportunities to
provide input to the decisions impacting them.
Throughout the natural gas IRP development, Avista promoted procedural equity in a
variety of ways:
• Engaged several advisory groups and encouraged participation in the areas of
equity, energy efficiency/demand response, energy assistance, resource planning
and the IRP's Technical Advisory Committee JAC).
• Modified the TAC meeting's frequency and duration based on feedback from
participant's feedback.
• Reviewed and modified presentations to ensure more use of common language
(non-technical) where possible.
• Recorded presentations for ease of access at later dates/times.
• Posted IRP calculation workpapers to provide transparency.
• Emailed presentations before meetings to provide more time to develop questions
and share concerns.
• Invited customer advocates to represent customers who may not be able to attend.
• Developed customer metrics in relation to resource planning to track.
• Invited all customers to participate in an open meeting to learn about the plan and
ask questions and provide comments.
• Posted input received from public meetings to support transparency of feedback.
Avista's Public Participation Plan (PPP)2 informed tactics and strategies to facilitate
meaningful engagement. The PPP supports broad representation from interested parties
and customer advocates, providing additional opportunities for identifying and
considering policies or procedures going forward. Although this plan was intended for
Washington's CETA compliance, learnings from it may be applied to natural gas
operations in all states.
2 See Docket No. UE-210295 for Avista's 2021 Public Participation Plan and Docket UE-210628 for its 2023
Public Participation Plan.
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Chapter 9: Customer Equity and Metrics
Distribution Justice
Distribution equity in the natural gas IRP pertains to the allocation of advantages and
disadvantages of goals and targets and ensures they are allocated between different
communities or across generations. It not only focuses on the actions taken but also on
the communities affected, considering variations among them, such as between the
subset of customers described above and the general customer base.
The foundation of energy equity emphasizes identifying benefits going beyond traditional
energy-related benefits. In IRP modeling, resource selection is based on either a
constraint (forcing an action) or a financial driver (cost or benefit) to incentivize resource
selection. Recent IRP's resource selection used additional modeling of non-financial
benefits, or Non-Energy Impacts (NEls), to highlight the interconnectedness of economic,
social, and environmental issues from resource selection.
To measure the distributional impacts of resource selection, energy burden is also being
monitored as a transparent, consistent, and measurable way to track progress and ensure
accountability in equity areas specific to affordability. Importantly, this is an initial step
taken by the Company to evaluate disparities in natural gas service.
Avista's approach to distributional justice is in its infancy stages and will continue to be
evaluated on an ongoing basis to determine the most optimal manner to capture this
important aspect of energy equity.
Restorative Justice
Restorative justice focuses on systematic approaches to prevent harm from occurring or
continuing in the future. Striving to minimize disparities between Named Communities
and all customers, particularly in relation to areas of affordability, availability, and
accessibility, amongst others. Avista incorporates restorative equity mainly through
energy efficiency and accounting for non-energy impacts. Energy efficiency specifically
for lower income households include additional economic value compared to other energy
efficiency programs by accounting for additional non-energy impacts. Furthermore, Avista
includes other non-energy impacts discussed later leading to higher avoided cost to
enable higher levels of energy efficiency and lower emitting options.
Achieving equity in operations is not limited to IRP planning. A broader, Company-
focused effort is being made to ensure an equitable transition — one that is fair, impartial,
and provides opportunities for all customers regardless of their unique circumstance.
Avista has several efforts in progress to help incorporate equity throughout Avista's
operations. These efforts include an equity focus on capital planning, energy efficiency
and weatherization, affordability, and distribution planning.
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Chapter 9: Customer Equity and Metrics
Non-Energy Impacts
To account for societal cost of Avista's resource decisions the use of non-energy impacts
(NEI) is included in resource decision making. These impacts may alter resource
decisions away from the utilities lowest cost but allow for a portfolio of resources
representing the lowest reasonable cost given the impacts of Avista decision on its
customers. Avista includes these NEIs differently between each of the states.
Avista during its February 1, 2024 TAC meeting3, Avista presented the potential items a
full NEI study may entail including the impacts of public health, safety, land use, water
use, economic impacts, community odor pollution, process bi-products, and pipeline
construction for renewable natural gas, hydrogen/synthetic methane, and natural gas
fuels. Avista ultimately decided against conducting a full study due to the cost of such a
study for Avista customers to carry. Although, Avista was able to conduct its own analysis
using public available sources for the following NEIs, included is a description of the NEI
and how it is used within the resource decision making process.
Social Cost of Greenhouse Gas (SCGHG)
The SCGHG is used as a cost adder to natural gas resources for determining the avoided
cost of gas for the energy efficiency in Washington state. This cost increases the avoided
cost of gas and therefore increases the number of cost-effective programs. Avista does
not include this cost for other resource selections. Although, a scenario described in
Chapter 8 demonstrates the impact if Avista used this cost adder for all resource
decisions. The SCGHG is determined by the Interagency Working Group on Social Cost
of Greenhouse Gas using the 2.5% discount rate for future costs. Figure 9.1 illustrates
the prices used for this analysis.
3 See Appendix 11
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Chapter 9: Customer Equity and Metrics
Figure 9.1: Social Cost of Carbon
$250 �SCGHG (2007$) —SCGHG (2022$)
SCGHG Nominal $
$200
0
H
$150
L
C
$100
a
$50
$0
CO r` 00 On O CV M 'q LO (.0 r~ 00 0) O T— N M Ict VI
N N N N M M M CO M M M M M M � � qI qI � qct
O O O O O O O O O O O O O O O O O O O O
N N N N N N N fV N N N N N N N N N N N N
Upstream Emissions
System emissions include any emissions from combustion including those emissions
upstream of the point of combustion like production, processing, transmission, and
equipment. This designation becomes important when placing a tax or cost of emissions
on the price per MMBtu. Avista assumes these upstream emissions are measured at the
standard 100-year Global Warming Potential (GWP) meaning a 29.8 multiplier of methane
from natural gas for the same mass of carbon dioxide. The levels of upstream emissions
in this plan are determined by production region, specifically in Canada and the Rockies
in the United States and multiplied by the associated emissions estimate.
Avista assumes a 0.77% upstream emissions rate for Canadian production and 2.64%
rate from the Rockies as calculated by an EDF study. From 2019 to 2023, nearly 83% of
Avista's natural gas was sourced from Canadian production leaving roughly 17% of
estimated upstream emissions to the Rockies region. Additionally, Avista adds 0.51%
from its local distribution lost and unaccounted for estimates. This estimate compares
billed data to metered data from June to July of each year. These estimates can be
overstated as the most likely case of losses are from meter reading issues or billing
timeframes or the dates a meter is read and billed compared to the specific calendar
month a bill is sent. Meter reading dates are specific to the days the information is
collected meaning one could be read on the 1 st of the month, while another could be read
on the 20t". These upstream emissions are included in the Social Cost of Greenhouse
4 as calculated in a study for the Tacoma LNG project
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Chapter 9: Customer Equity and Metrics
Gas scenario and for estimating energy efficiency avoided cost as explained in Chapter
and are used to consider all emissions from production to the burner tip for use. The
Climate Protection Plan and Climate Commitment Act do not consider upstream
emissions for compliance, but rather site source emissions only.
The final upstream emissions from methane (CH4) in carbon equivalents add nearly 12.09
pounds per MMBtu as shown in Table 9.1:
Table 9.1: Avista Specific LDC Natural Gas Emissions
Combustion Avista Specific Natural Gas
CO2 116.88 116.88
CHa 0.0022 0.06556
N20 0.0022 0.6006
Total Combustion 117.61
Upstream
CHa 0.406 12.55
Total 130.09
Table 9.2 illustrates the Global Warming Potential; the Intergovernmental Panel on
Climate Change released their 6t" assessment study defining these impacts to global
warming in units of CO2e.
Table 9.2: Global Warming Potential (GWP) in CO2 Equivalents
i •
Gas Year &_Year
CO2 1 1
CHa 29.8 83
N20 273 268
Safety
Avista is considering customer safety to add a financial value to the cost of natural gas
resources for resource selection. Avista estimates this value by considering the potential
deaths related to carbon monoxide poisoning as a population share of overall deaths6.
Safety incidents from the natural gas system is also included in this estimate as provided
by PHMSA7 and is based on Avista's percentage of total throughput of natural gas in
Idaho, Oregon and Washington and the value of a human life. Avista uses this NEI only
5 From the 6th Assessment of the Intergovernmental Panel on Climate Change
6 Non-Fire Carbon Monoxide Deaths Associated with the Use of Consumer Products 2020 Annual
Estimates
US DOT Pipeline and Hazardous Materials Safety Administration
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Chapter 9: Customer Equity and Metrics
for Washington and Oregon resource decision making. Figure 9.2 demonstrates the
safety cost adder starting $0.63 per Dth in 2026 escalating to $0.95 per Dth by 2045.
-figure 9.2: ,. ston.,!r Safety Imp.. ,
$1.00
$0.90
$0.80
$0.70 •
$0.60
$0.50
a
6, $0.40
$0.30
$0.20
$0.10
$0.00
c0 1` M Q1 O N M � LO c0 r-- M aM O N M LO
N N N N M M M M M M M M M M � It It �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Air Emissions
Avista also includes a financial adder for air emissions from the combustion of natural gas
for resource selection in Washington and Oregon, these include N2O, CH4 and CO2.
Figures 9.3 to 9.5 represent these costs based on the direct use of natural gas. These
estimates are derived from the Interagency Working Group on Social Cost of Greenhouse
Gas. Although the cost of CO2 price adder is only included in the energy efficiency
potential analysis and the Social Cost of Greenhouse Gas Scenario, this is due to the
Climate Commitment Act's carbon allowance prices accounts for the actual financial value
of these emissions as directed by Washington State's legislature.
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Chapter 9: Customer Equity and Metrics
Figure 9.3: CO2 Cost per Dth (Nominal $)
$12
$10 ,
N
U $8
46
Z $6
L
60
$4
$2 - - - - - -
CD 1� CO Cif O N M g LO W 1*— CO O O N M q* LO
N N N N M M M M M M M M M M 'q
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 9.4: CHa Cost per Dth (Nominal $)
$0.008
$0.007
$0.006
U
0
$0.005
0
$0.004
$0.003
a
$0.002
$0.001 - - - - - - - - - - - - - - - - - - - -
CD P­ CO O O N M qq LO CD 1- O O O N M "I LO
N N N N M M M M M M M M M M 'q
O O O O O O O O O O O O O O O O O O O O
NNNNNNNNNNNNNNNNNNNN
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Chapter 9: Customer Equity and Metrics
Figure 9.5: N20 Cost per Dth (Nominal $)
$0.07
$0.06
O $0.05
z
c $0.04
a�
$0.03
a
$0.02
$0.01 - - - - - - - - - - - - - - - - - - - -
W t` co M O N MR* LO W r` 00 M O N M 10 LO
N N N N M M M M M M M M M M 1qt* q1q1
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
nerav Efficiencv Proaram<
Avista engaged with DNV (formerly DNV-GL) to develop and quantify a list of NEIs for
Avista's electric and natural gas programs, along with a gap analysis of areas for future
NEI development. These efforts identified several NEIs for low-income, residential, and
commercial/industrial customers, including those affecting participants, society, and the
utility.
While basic conservation efforts consider the effect of energy efficiency measures on the
utility's system by deferring capital investments, NEIs provide an opportunity to assign
value to what is received by the customer, providing a link between an efficiency measure
and a measurable customer benefit. As such, NEI values are included in Avista's TRC
cost-effectiveness test as a benefit to the customer. Avista started utilizing NEI values in
its benefits calculations for TRC and PCT cost-effectiveness tests starting with Avista's
2022 Annual Conservation Report, which was filed on June 1, 2023. Avista has
incorporated updated NEI values into its TRM and continues to utilize NEI values in its
cost-effectiveness calculations. NEI values are tracked on a per-measure basis and range
from less than $.01 per therm up to $1.91 per therm. Low-Income Program measures
have the highest non-energy benefit value to customers because of the health and safety
benefits provided to qualified customers at no cost.
Other categories of non-energy impact values that are quantified in Avista's NEI values
include avoided illness from pollution; reductions in noise, increases in productivity, ease
Avista Corp 2025 Natural Gas IRP 232

Chapter 9: Customer Equity and Metrics
of selling or leasing a space based on improvements, avoided costs of insurance/fire
damage, and NEls related to energy burden reduction. Examples include reductions in
bad debt write-offs' reductions in calls to the utility' reductions for utility carrying costs on
arrearages, and thermal comfort and operations savings for customers. For each
measure in Avista's portfolio, the NEI value for each identified category is aggregated and
then matched against an NEI database to create an Avista-specific NEI value for that
measure.
Power Act Adder
Avista's avoided cost for energy efficiency includes the Northwest Power Act's 10%
energy efficiency preference. This adder is applied to energy efficiency selection in
Washington only to further encourage energy efficiency.
Economic
Avista acquired IMPLAN$ to estimate the economic benefits of added natural gas
infrastructure and supply. IMPLAN is a leading national economic impact analysis tool
used to gain precise insights into local, regional, and national economies. Avista's intent
was to use this information to influence resource decisions by including the induced
economic benefits as NEI. Avista ultimately decided to not include this as an NEI and
rather measure the economic benefit and induced jobs as a metric.
Customer Equity Metrics
Avista committed in its first Technical Advisory Committee meeting to include metrics
regarding customer impacts like Customer Benefit Indicators (CBI's) used in other forums.
These metrics are used to determine the impacts of the Preferred Resource Strategy to
our customers. In this first meeting Avista agreed to estimate future greenhouse gas
emissions, customer rates, energy burden, and other air emissions. In addition to these
metrics Avista is also including induced economic benefits and job creation of the plan.
Air Emissions
The PRS expects natural gas and renewable natural gas to service customers into the
future to assist in complying with state greenhouse reduction goals. Although, even if
Avista uses all direct use renewable natural gas to serve customers, there is likely
emissions from the combustion of the fuel regardless of climate program rules of
accounting for those emissions. The following Figures (9.6 to 9.11) show the actual air
emissions (carbon dioxide (CO2), nitrous oxide (N2O), and methane (CH4)from the PRS's
resource selection rather than the estimated emissions based upon compliance of state
programs. Avista's reductions shown in the estimates are from energy efficiency, changes
in customer use, and expected carbon capture and does not include the emission
reductions for any Renewable Thermal Credits (RTCs) purchased.
8 IMPLAN I Economic Impact Analysis Software
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Chapter 9: Customer Equity and Metrics
Figure 9.6: Washington Direct COz Emissions
1,400,000
1,200,000
c
1,000,000
800,000
U
600,000
400,000
200,000
0
CD r` CO M O N Mlc* In c0 r` co M O N M 10 LO
N N N N M M M M M M M M M M MT � Iq MT
O O M O O O O M O O O O M O O O O O M O
NNNNNNNNNNNNNNNNNNNN
Figure 9.7: Oregon Direct COs Emissions
700,000
600,000
500,000
400,000
U
a 300,000
200,000
100,000
0
CD r~ co M O � N M Iq LO CD r~ M M O N M Iq LO
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Chapter 9: Customer Equity and Metrics
Figure 9.8: Washington Direct N20 Emissions
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7,000
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Figure 9.9: Oregon Direct N20 Emissions
4,000
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Chapter 9: Customer Equity and Metrics
Figure 9.10: Washington Direct CHa Emissions
900
800
700
0
600
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300
200
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Figure 9.11: Oregon Direct CHa Emissions
450
400
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Chapter 9: Customer Equity and Metrics
Economic Impacts
Avista's resource choices of acquiring fuel and energy efficiency within the local economy
will improve community vitality, this is mainly accomplished through capital investment
and job creation. Using the IMPLAN model, Avista estimates the following economic
activity from Avista resource choices of RNG and Energy Efficiency. Oregon selects
nearly all RNG in the PRS so no other states are shown in Figure 9.12 for economic
impacts. On average, each dekatherm of capital spend creates an additional 28% of
induced economic growth in Oregon. Figures 9.13 and 9.14 show the number of job
creations based on annual energy efficiency spend and in Oregon the total induced jobs
including those from RNG.
Figure 9.12: Oregon Induced Economic Growth from RNG
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Chapter 9: Customer Equity and Metrics
Figure 9.13: Oregon Induced Job Creation from RNG/Energy Efficiency
140
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Figure 9.14: Washington Induced Job Creation from Energy Efficiency
35
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Chapter 9: Customer Equity and Metrics
Affordability
The first consideration of understanding customer's energy equity is to comprehend the
current landscape of residential customer's gas cost. This analysis describes the
components of the customer bill on a winter monthly perspective and an annual cost
perspective to give understanding to typical bill size and what makes up a customer's
natural gas energy cost. Following this analysis is an estimate of customers with an
energy burden exceeding 6% of gross income is performed to identify the quantity of
customers who may have challenges paying their energy bills.
Current Customer Space Heating Costs
Residential customers use natural gas for space heating, water heating, cooking, and
other purposes, but the main purpose is space heating. The intention of this analysis
focuses on the cost of residential space heating as it's the major component of a customer
bill and is a necessity in Avista's climate zones. Winter monthly bills are the greatest
challenge for customers, this analysis demonstrates a comparison of current rates for
each of Avista's jurisdictions for the same natural gas consumption using actual tariff rates
as of February 20259. The analysis demonstrates the highest monthly bill in is typically in
the month of January and the total cost over a year for customer's space heating needs.
This analysis does not include water heating or any other use of natural gas service. In
addition, this analysis shows the alternative cost if the customer was heating with an
electric furnace and heat pump for comparison if the customer electrified their home's
heating system.
Figure 9.15 shows an example of the January bill for a customer using 90 therms of
natural gas for each jurisdiction's residential rate class10. Also included is a comparative
electric heating bill if the customer uses electricity for heating11. The main charges for
natural gas is the Base Rate in light blue and the Commodity in dark blue. The Commodity
is the price of the physical gas purchased for the customer, whereas the Base Rate
includes pipelines, transport, and utility administration. The amount paid for DSM (energy
efficiency), LIRAP (low-income subsidy), and "other" is also included to separate utility
costs versus other costs. The "Other category includes items such as insurance,
decoupling, taxes, and other small or temporary adjustments and in many cases can be
a rate reduction12. Lastly, for Washington customers, the CCA is the direct cost of the
Climate Commitment Act 13. For the electric bill comparison, Avista's electric rates are
used, except in Oregon, where Pacific Power is used as the primary electric provider in
9 Excludes the temporary Washington CCA adjustment, schedule 162.
10 Washington includes multiple rate schedules due to CCA requirements for different rates due to either
income or age of home.
11 Avista estimates kWh demand by using 77% of the 293 kWh to equal an mmBTU. The 77% is used for
January to account for the efficiency of a heat pump vs a natural gas furnace. The cost of installing or
switching to electric heat is not included.
12 See .riffs in WA, ID, & OR I Avist for compete list of tariff adjustments for
both electric and natural gas rates.
13 The CCA prices for the pre 2021 residence will increase over time to match the post 2021 customer rates.
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Chapter 9: Customer Equity and Metrics
Avista's gas service area, although some customers in any of the jurisdictions may have
different rates depending on the electric provider. Also, regarding the electric heating
alternative, the basic charge is not included as the customer would have this charge
regardless of its space heating choice. This analysis shows a significant lower cost for
customer heating using natural gas as compared to electric alternatives in each
jurisdiction during the heating season.
Figure 9.15: Example Space Heating Winter Month Bill by Jurisdiction (80 therms)
$400
$350 $299
$300 $263
00 $250 $190
$200
L $150 $121 $124 $138 $113
$100 $75
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Due to jurisdictions having different monthly customer charges, another way to look at the
cost of service is the annual bill shown in Figure 9.16. A customer may opt for levelized
billing to address bill spikes seen in the monthly perspective, so this view shows an overall
impact on pricing. When comparing the annual bill for space heating (assumes 465
therms over the year), natural gas heating remains the lowest cost option. Also notable
is the Idaho cost on an annual basis is like Washington when excluding Washington's
tariff adders for LIRAP, Other, and CCA. This is different than the monthly view in Figure
9.16 due to Idaho's higher fixed monthly charge.
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Chapter 9: Customer Equity and Metrics
Figure 9.16: Example Space Heating Annual Bill by Jurisdiction (465 therms)
$19350 $19218
$19150 $19033
00 $950
2, $755 $700 $702 $775 $642
$750 $526
0 $550
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Energy Burden
There are three forecastable metrics14 related to household energy burden included
within resource selection modeling, each excluding energy assistance funds:
• The number of households with energy burden exceeding 6% of income,
• Percentage of customers with excess energy burden, 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 the LEAD tool.
Total energy burden includes all fuels, natural gas, electricity, wood, propane and heating
oil, at a specific location. 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 by general
customers and disadvantaged customers. Households using wood, propane, or heating
oil were included based on data in the 2022 RBSA and are considered in this analysis.
Customer income is escalated using inflationary expectations in this IRP. Lastly, the cost
of the energy used by the customer is estimated using a rate forecast based on the
14 Separate tracking on a forecasted basis for known low-income and Named Communities cannot be
completed until additional data is gathered.
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Chapter 9: Customer Equity and Metrics
resources selected through the IRP or estimated costs of wood, propane or heating oils
combined with inflation.
The first metric illustrates the forecast of the number of customers with excess energy
burden (see Figure 9.17 and 9.18) over the IRP planning horizon. These customers have
a combined energy bill exceeding 6% of their income to be included in this metric.
Customers can fall into this metric due to high usage or low income. In 2026,
approximately 38,000 customers in Washington out of 250,000 will be energy burdened.
The absolute number of customers stays relatively flat until 2040 (Oregon) and 2045
(Washington), but as a percentage of energy total, customers with energy burden
decreases until clean energy targets are enforced along with the higher expected costs
to comply with the 100% clean baseline emissions goals. when significant resources are
retired, and additional clean generation is added to ensure reliability and 100% clean
energy in all hours. Forecasted energy burden estimates show a significant increase
compared to the 2020 LEAD study, where only 3.2% of Washington and 3.6% of Oregon
customers were considered energy burdened. The only other way to address energy
burden within a resource plan is to use energy efficiency to lower energy use and develop
dedicated resources for low-income customers. Both strategies are presumed in this plan,
but all result in financial energy assistance, further creating pressures on retail energy
pricing.
Figure 9.17: OR Customers with Excess Energy Burden
(Before Energy Assistance)
40,000 40%
% of Customers with Energy
Burden 35%
30,000 Number of Customers with / 30%
Energy Burden
-- � 25%
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Chapter 9: Customer Equity and Metrics
Figure 9.18: WA Customers with Excess Energy Burden
(Before Energy Assistance)
0
00 w % of Customers with Energy Burden o
Number of Customers with Energy Burden 30%
40,000
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30,000 ' , 20%
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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 achieve the 6%
level. The average excess energy burden growth is shown in Figure 9.19 and 9.20. This
metric is expected to increase both in nominal and real (2026 dollars) values though the
real increase is modest compared to the nominal increase at 1% a year in Oregon and
0.6% a year in Washington above inflation. The difference between the two demonstrates
the impact of inflation compared to the impact of rate increases. Oregon has a goal for
electric utilities to be 100 percent15 below baseline emissions by 2040. This impacts rates
5 years earlier than Washingtons goal of 100 percent supply free of greenhouse gas
emissions by 204516
15 Department of Environmental Quality : Oregon Clean Energy Targets : Action on
Climate Change : State of Oregon
16 Clean Energy Transformation Act (CETA) — Washington State Department of
Commerce
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Chapter 9: Customer Equity and Metrics
Figure 9.19: OR Customers with Excess Energy Burden (Before Energy
Assistance)
$2,500
P Average excess burden per household (nominal $)
—Average excess burden per household (real $2026)
$2,000
$1,500
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Figure 9.20: WA Customers with Excess Energy Burden (Before Energy
Assistance)
$2,500
Average excess burden per household (nominal $)
$2,000 Average excess burden per household (real $2026)
$1 ,500
� i
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Chapter 10: Distribution Planning
10. Distribution Planning
Section Highlights:
• A Non-Pipeline Alternative analysis will be considered going forward for all projects
meeting cost criteria in Oregon and Washington.
• Distribution planning is a continual process used to incorporate detailed operating
conditions to maintain a safe and reliable resource.
• Two projects have been identified for NPA in Washington for 2025 completion.
Avista's IRP evaluates the safe, economical, and reliable full-path delivery of natural gas
from basin to the customer meter. Securing adequate natural gas supply and ensuring
sufficient pipeline transportation capacity to Avista's city gates become secondary issues
if distribution system growth behind the city gates increases faster than expected and the
system becomes severely constrained. Important parts of the distribution planning
process include forecasting local demand and growth, determining potential distribution
system constraints, analyzing possible solutions and estimating costs for eliminating
constraints.
Analyzing resource needs to this point has focused on ensuring adequate capacity to the
city gates, especially during a peak event. Distribution planning focuses on determining if
there will be adequate pressure during a peak hour, downstream of the city gates within
the distribution system. Despite this altered perspective, distribution planning shares
many of the same goals, objectives, risks, and solutions as integrated resource planning.
Avista's natural gas distribution system consists of approximately 3,700 miles of
distribution main and service pipelines in Idaho, 3,900 miles in Oregon and 6,300 miles
in Washington; as well as numerous regulator stations, service distribution lines,
monitoring and metering devices, and other equipment. Currently, there are no storage
facilities or compression systems within Avista's distribution system. Distribution network
pipelines and regulating stations operate and maintain system pressure solely from the
gas provided by the interstate transportation pipelines.
Distribution System Planning
Avista conducts two primary types of evaluations in its distribution system planning
efforts: capacity requirements and integrity assessments.
Capacity requirements include distribution system reinforcements and expansions.
Reinforcements are upgrades to existing infrastructure or new system additions to
increase system capacity, reliability, and safety. Expansions are new system additions to
accommodate new demand. Collectively, these reinforcements and expansions are
distribution enhancements.
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Chapter 10: Distribution Planning
Ongoing evaluations of each distribution network in the five primary service territories
identify strategies for addressing local distribution capacity requirements resulting from
customer growth. Customer growth assessments are made based on factors including
IRP demand forecasts, monitoring gate station flows and other system metering, new
service requests, field personnel discussion, and inquiries from major developers.
Avista regularly conducts integrity assessments of its distribution systems. Ongoing
system evaluation can indicate distribution-upgrading requirements for system
maintenance needs rather than customer and load growth. In some cases, the timing for
system integrity upgrades coincides with growth-related expansion requirements. These
planning efforts provide a long-term planning and strategy outlook and integrate into the
Company's capital planning and budgeting process.
Gas planning models are also compared with capacity limitations at each city gate station.
Referred to as city gate analysis, the design day hourly demand generated from planning
analyses must not exceed the actual physical limitation of the city gate station. A capacity
deficiency found at a city gate station establishes a potential need to rebuild or add a new
city gate station.
Network Desian Fundamental-
Natural gas distribution networks rely on pressure differentials to flow natural gas from
one place to another. When pressures are the same on both ends of a pipe, the natural
gas does not move. As natural gas exits the pipeline network, it causes a pressure drop
due to its movement and friction. As customer demand increases, pressure losses
increase, reducing the pressure differential across the pipeline network. If the pressure
differential is too small across the regulator, flow stalls and the network could run out of
pressure.
It is important to design a distribution network to ensure intake pressure from gate stations
and/or regulator stations within the network is high enough to maintain an adequate
pressure differential when natural gas leaves the network.
Not all natural gas flows equally throughout a network. Certain points within the network
constrain flow and restrict overall network capacity. New network constraints can occur
as demand requirements evolve. Anticipating these demand requirements, identifying
potential constraints, and forming cost-effective solutions with sufficient lead times without
overbuilding infrastructure are the key challenges in network design.
Computer Modelinc
Developing and maintaining effective network design is aided by computer modeling for
network demand studies. Demand studies have evolved with technology to become a
highly technical and powerful means of analyzing distribution system performance. Using
a pipeline fluid flow formula, a specified parameter for each pipe element can be
Avista Corp 2025 Natural Gas IRP 246

Chapter 10: Distribution Planning
simultaneously solved. Many pipeline equations exist, each tailored to a specific flow
behavior. These equations have been refined through years of research to the point
where modeling solutions closely resemble actual system behavior.
Avista conducts network load studies using DNV GL's Synergi Gas software. This
modeling tool allows users to analyze and interpret solutions graphically.
Determining Peak Demand
Avista's distribution network is comprised of high pressure (90-500 psig) and intermediate
pressure (5-60 psig) mains. Avista operates its intermediate networks at a maximum
pressure of 60 psig or less for ease of maintenance and operation, public safety, reliable
service, and cost considerations. Since most distribution systems operate through
relatively small diameter pipes, there is essentially no line-pack capability for managing
hourly demand fluctuations. Line pack is the difference between the natural gas contents
of the pipeline under packed (fully pressurized)and unpacked (depressurized) conditions.
Line pack is negligible in Avista's distribution system due to the smaller diameter pipes
and lower pressures. In transmission and inter-state pipelines, line-pack contributes to
the overall capacity due to the larger diameter pipes and higher operating pressures.
Core demand typically has a morning peaking period between 6 a.m. and 10 a.m. and
the peak hour demand for these customers can be as much as 50% above the hourly
average of daily demand. Because of the importance of responding to hourly peaking in
the distribution system, planning capacity requirements for distribution systems uses peak
hour demand.'
Distribution System Enhancements
Demand studies facilitate modeling multiple demand forecasting scenarios, constraint
identification and corresponding optimum combinations of pipe modification, and
pressure modification solutions to maintain adequate pressures throughout the network.
Distribution system enhancements do not reduce demand, nor do they create additional
supply. However, enhancements increase the overall capacity of a distribution pipeline
system while utilizing existing gate station supply points. The two broad categories of
distribution enhancement solutions are pipelines and regulators.
Pipelines
Pipeline solutions consist of looping, upsizing, and uprating. Pipeline looping is the most
common method of increasing capacity in an existing distribution system. Looping
involves constructing new pipe parallel to an existing pipeline to relieve the constraint
point. Constraint points inhibit flow capacities downstream of the constraint creating
inadequate pressures during periods of high demand. When the parallel line connects to
This method differs from the approach for IRP peak demand planning, the IRP focuses on peak "day"
requirements to the city gate.
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Chapter 10: Distribution Planning
the system, this alternative path allows natural gas flow to bypass the original constraint
and bolsters downstream pressures. Looping can also involve connecting previously
unconnected mains. The feasibility of looping a pipeline depends upon the location where
the pipeline will be constructed. Installing natural gas pipelines through private
easements, residential areas, existing paved surfaces, and steep or rocky terrain can
increase the cost to a point where alternative solutions are more cost effective.
Pipeline upsizing involves replacing existing pipe with a larger size pipe. The increased
pipe capacity due to increased cross-sectional area of the pipe, results in less friction,
and therefore a lower pressure drop. This option is usually pursued when there is
damaged pipe or where pipe integrity issues exist. If the existing pipe is otherwise in
satisfactory condition, looping augments existing pipe, which remains in use.
Pipeline uprating increases the maximum allowable operating pressure of an existing
pipeline. This enhancement can be a quick and relatively inexpensive method of
increasing capacity in the existing distribution system before constructing more costly
additional facilities. However, safety considerations and pipe regulations may prohibit the
feasibility or lengthen the time before completion of this option. Also, increasing line
pressure may produce leaks and other pipeline damage creating costly repairs. A
thorough review is conducted to ensure pipeline integrity and safety are accounted for
before pressure is increased.
Regulators
Regulators, or regulator stations, reduce pipeline pressure at various stages in the
distribution system. Regulation provides a specified and constant outlet pressure before
natural gas continues its downstream travel to a city's distribution system, customer's
property, or natural gas appliance. Regulators also ensure flow requirements are met at
a desired pressure regardless of pressure fluctuations upstream of the regulator.
Regulators are at city gate stations, district regulator stations, farm taps and customer
services.
Compression
Compressor stations present a capacity enhancing option for pipelines with significant
natural gas flow and the ability to operate at higher pressures. Most often these are used
on interstate transportation pipeline systems, upstream of Avista's gas facilities. For
pipelines experiencing a relatively high and constant flow of natural gas, a large volume
compressor installation along the pipeline will boost downstream pressure.
A second option is the installation of smaller compressors located close together or
strategically placed along a pipeline. Multiple compressors accommodate a large flow
range and use smaller and very reliable compressors. These smaller compressor stations
are well suited for areas where natural gas demand is growing at a slower and steady
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Chapter 10: Distribution Planning
pace, allowing for installation of less expensive compressors over time to serve growing
customer demand into the future.
Compressors are an option to resolving system constraints; however, regulatory, and
environmental approvals to install a compressor station, along with engineering and
construction time can be a significant deterrent. Adding compressor stations typically
involves considerable capital expenditure. Based on Avista's detailed knowledge of the
distribution system, there are no foreseeable plans to add compressors to the distribution
network.
Distribution Scenario Decision-Making Process
After achieving a working load study, analyses are performed on every system at design
day conditions to identify areas where potential outages may occur due to inadequate
capacity.
Avista's design Heating Degree Day (HDD)for distribution system modeling is determined
using a 99% statistical probability method for each given service area as discussed in
. This practice is consistent with the peak day demand forecast utilized in other
sections of Avista's Natural Gas IRP.
Utilizing a peak planning standard based on a statistical probability method of historical
temperatures is sensible even though extreme temperatures are rare. Given the potential
impacts of an extreme weather event on customers' personal safety and potential
damage to customer's appliances and Avista's infrastructure, it is a prudent and regionally
accepted planning standard.
These areas of concern are then risk ranked against each other to ensure the highest risk
areas are corrected first. Within a given area, projects/reinforcements are selected using
the following criteria:
• The shortest segment(s) of pipe that improves the deficient part of the distribution
system.
• The segment of pipe with the most favorable construction conditions, such as ease
of access or rights or traffic issues.
• Minimal to no water, railroad, major highway crossings.
• The segment of pipe that minimizes environmental concerns including minimal to
no wetland involvement, and the minimization of impacts to local communities and
neighborhoods.
• The segment of pipe that provides opportunity to add additional customers.
• Total construction costs including restoration.
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Chapter 10: Distribution Planning
Once a project/reinforcement is identified, the design engineer or construction project
coordinator begins a more thorough investigation by surveying the route and filing for
permits. This process may uncover additional impacts such as moratoriums on road
excavation, underground hazards, discontent among landowners, etc., resulting in
another iteration of the above project/reinforcement selection criteria. Figure 10.1
provides a schematic representation of the distribution scenario process.
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Chapter 10: Distribution Planning
Figure 10.1: Distribution Scenario Process
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Chapter 10: Distribution Planning
Non-Pipe Alternatives
An evaluation of non-pipe alternatives (NPAs) is considered against pipeline capacity
reinforcements, when not related to safety, compliance, or road moves. NPAs will only be
considered when the cost of an upgrade is at a level high enough where a NPA may be
cost effective, can be accomplished prior to the time the upgrade is needed, and can lead
to a great enough reduction of demand to defer or eliminate the need for the upgrade.
Total project cost consideration for cost effectiveness differ between jurisdictions. In
Washington a $500'0002 or greater cost estimate requires a NPA where in Oregon a
million-dollar threshold this analysis is required3.
Avista's methodology for NPA analyses, as directed by the OPUC4 and adopted by the
WUTC, is as follows:
a. NPA analysis will be performed for supply-side resources (these include but are
not limited to all resources upstream of Avista's distribution system and city gates,
and supply-side contracts) and for distribution system reinforcements and
expansion projects that exceed a threshold of $1 million for individual projects or
groups of geographically related projects (a group of projects that are
interdependent or interrelated).
b. NPA analysis will include cost benefit analysis that reflects an avoided GHG
compliance cost element consistent with a high cost estimate of future alternative
fuels prices. Non-Energy Impacts must be included as part of the NPA analysis.
c. NPA analysis will include electrification, targeted energy efficiency, targeted
demand response, and other alternative solutions.
d. NPA analysis should look forward five years to allow ample time for evaluation and
implementation.
e. NPA analysis will include an explanation of solutions considered and evaluated
including a description of the projected timeline and annual implementation rate
for the solutions evaluated, the technical feasibility of the solutions, and the
strategy to implement the solutions evaluated.
f. NPA analysis should include an explanation of the resulting investment selection
(either NPA or a traditional investment) including the costs and ranking of the
solutions, and the criteria used to rank or eliminate them.
i. If a NPA is not selected and the reason is insufficient implementation time,
it should include steps the Company will take to perform NPA analysis to
provide sufficient implementation time for future projects.
Specific to Washington, the WUTC required that:
z WUTC Docket UE-240006 and UG-240007 (Consolidated), Order 08, December 20, 2024 at 1309.
3 OPUC Docket UG 461, Order No. 23-384, October 26, 2023—Appendix B, Second Settlement Stipulation
#21.
4 OPUC Docket LC 81, Order No. 24-156, May 31, 2024—Attachment C.
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• Avista must examine the relationship between any NPA and the Climate
Commitment Act (CCA) but may not assume that all CCA allowances will be
purchased at the ceiling price.
• Avista must provide an explanation of the resulting investment selection (either the
NPA or a traditional investment) that compares the costs of both projects, but
Avista is not required to rank or score any NPA in its evaluation process.5
To date, Avista has not had a project that meets the criteria to perform an NPA analysis.
However, Avista will be performing an NPA analysis on at least two projects related to
customer grown in Washington that exceed $500,000 in 2025, as required by the WUTC.6
The two projects identified for NPA analysis in Washington are discussed below.
Conservation Resources
The evaluation of distribution system constraints includes consideration of targeted
conservation resources to reduce or delay distribution system enhancements. The
consumer is still the ultimate decision-maker regarding the purchase of a conservation
measure. Because of this, Avista attempts to influence energy efficiency through the
measures discussed in but does not depend on estimates of peak day demand
reductions from energy efficiency to eliminate near-term distribution system constraints.
Over the longer-term, targeted energy efficiency programs may provide a cumulative
benefit that could offset potential constraint areas and may be an effective strategy.
Planning Results
Table 10.1 summarizes the cost and timing, as of the publication date of this IRP, of major
distribution system enhancements addressing growth-related system constraints, system
integrity issues and the timing of expenditures.
The Distribution Planning Capital Projects criteria includes:
• Prioritized need for system capacity (necessary to maintain reliable service to firm
sales gas customers);
• Scale of project (large in magnitude and will require significant engineering and
design support);
• Budget approval (will require approval for capital funding); and,
• Projects are subject to change and will be reviewed on a regular basis.
These projects are preliminary estimates of timing and costs of major reinforcement
solutions whose costs exceed the limits as discussed above. The scope and needs of
distribution system enhancement projects generally evolve with new information requiring
5 WUTC Docket UE-240006 and UG-240007 (Consolidated), Order 08, December 20, 2024 at 1309.
6 Ibid ¶311.
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Chapter 10: Distribution Planning
ongoing reassessment. Actual solutions may differ due to differences in actual growth
patterns and/or construction conditions that differ from the initial assessment and timing
of planned completion may change based on the ongoing reassessment of information.
The following discussion provides information about key near-term projects.
Kettle Falls, WA High Pressure Reroute: The Kettle Falls high pressure line is
approximately 80 miles long and serves the communities of Addy, Chewelah, Colville,
Deer Park, Kettle Falls, and some additional rural towns. This project is considered an
integrity driven project, not a capacity project. Sections of this high-pressure pipeline are
currently classified as "transmission" due to the operating conditions and physical pipe
characteristics. This pipeline is in close proximity to high occupancy dwellings and
businesses (high consequence areas or HCA's), making it necessary for Avista to either
lower the pressure or reroute these sections. This project will introduce a new high-
pressure pipeline along a different route, allowing Avista to maintain capacity needs and
eliminate "transmission" high pressure mains in any HCA's. Project design will begin in
2026-27 with construction anticipated in 2027-28. An NPA analysis will be completed on
this project and will include targeted energy efficiency analysis. Avista will complete this
analysis in 2026.
Airway Heights, WA High Pressure Reinforcement: Although recently enhanced, the
Airway Heights high pressure gas main has provided natural gas to one of the fastest
growing regions in all of Avista's service territories. Currently there are several industrial
customers considering the Airway Heights location for new facilities or expansion. A
reinforcement will provide additional capacity for industrial growth and ensure reliable
pressure at the end of the gas main. This main also supplies a major regulator station
supporting the Downtown Spokane neighborhoods. An NPA analysis will be completed
on this project in 2025 along with the Kettle Falls High Pressure Reroute above in 2025.
Schweitzer, ID High Pressure Reinforcement: Recent growth in the Schweitzer Resort
Community is causing the distribution to approach maximum capacity. Additional growth
is planned and preliminary studies recommend extending the existing high pressure
further up Mountain Road to be closer to the Schweitzer growth areas. Design and
construction will be determined after growth expectations are confirmed.
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Chapter 10: Distribution Planning
Table 10.1: High Pressure - Distribution Planning Capital Projects
i
Kettle Falls High Pressure Reroute, WA (compliance- --- $100,000 $2,000,000 ---
driven)
Airway Heights High Pressure Reinforcement, WA TBD TBD TBD TBD
(growth-driven)
Schweitzer High Pressure Reinforcement, ID (growth- TBD TBD TBD TBD
driven)
Table 10.2 shows city gate stations identified as possibly over utilized or under capacity.
Estimated cost, year, and the plan to remediate the capacity concern are shown.
These projects are preliminary estimates of timing and costs of city gate station upgrades.
The scope and needs of each project generally evolve with new information requiring
ongoing reassessment. Final solutions may change due to differences in actual growth
patterns and/or construction conditions that differ from the initial assessment. The city
gate station projects in Table 10.2 are periodically reevaluated to determine if upgrades
need to be accelerated or delayed. Those assigned a TBD year have relatively small
capacity constraints, and thus will be monitored.
Table 10.2: City Gate Station Upgrades
. .
16 Gate Station Project to co�—i�
6- Rernediate
Malin, OR Malin #27T01 TBD - TBD
Medford, OR Medford TBD - TBD
#2431
Pullman, WA Pullman #350 TBD - TBD
Colton, WA Colton #315 TBD - TBD
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Chapter 11: Action Plan
11 . Action Plan
Action items position Avista to provide the best cost/risk resource portfolio to support and
improve IRP planning going forward. The Action Plan identifies supply and demand side
resource needs and highlights key analytical needs in the near term. It also highlights
essential ongoing planning initiatives and natural gas industry trends Avista will monitor
as a part of its planning processes.
2023 Avista Action Items
1. Purchase allowances or offsets for compliance to the Climate Commitment Act for
years 2023, 2024, 2025 and 2026 to comply with emissions reduction targets.
Result: Avista procured allowances in 2023 and 2024 based on expected
number of instruments needed to offset total emissions in Washington.
2. Begin to offer a Washington transport customer EE program by 2024 with the goal of
saving 35,000 therms.
Result: This program was delayed due to the initiative to repeal the CCA.
Avista stood up a carbon reduction program in 2025 and will begin offering
this program to eligible transport customers where Avista has the
responsibility to cover emissions for compliance to the CCA (Less than
25,000 tonnes of emissions).
3. Explore methods for using Non-Energy Impact (NEI) values in future IRP analysis to
account for social costs in Oregon and Washington to ensure equitable outcomes.
Result: Avista has included induced safety and emissions impacts
estimates for new resources. Avista also created job creation and
economic impacts estimates based on these resources as selected in the
PRS. This information can be found in VI ICIPMN 0.
4. Explore using end use modeling techniques for forecasting customer demand.
Result: Avista utilized an end use forecast as developed by AEG in all
analysis included within the 2025 IRP and discussed in detail in Chapter 3.
5. Consider contracting with an outside entity to help value supply side resource options
such as synthetic methane, renewable natural gas, carbon capture, and green
hydrogen.
Result: Avista contracted with ICF to estimate alternative resources
including various production methods for synthetic methane, renewable
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Chapter 11: Action Plan
natural gas, hydrogen, carbon capture utilization and sequestration and
renewable thermal credits. These inputs and results can be found in
Chapter 6 with the final report in Appendix 6.
6. Regarding high pressure distribution or city gate station capital work, Avista does not
expect any supply side or distribution resource additions to be needed in our Oregon
territory for the next four years, based on current projections. However, should
conditions warrant that capital work is needed on a high-pressure distribution line or
city gate station to deliver safe and reliable services to our customers, the Company
is not precluded from doing such work. Examples of these necessary capital
investments include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
— Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or
maintenance of system associated with reliability
• Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel
replacement, etc.
— Anticipated PHMSA guidance or rules related to 49 CFR Part §192
that will likely require additional capital to comply
• Officials from both PHMSA and the AGA have indicated it is
not prudent for operators to wait for the federal rules to
become final before improving their systems to address these
expected rules.
— Other special contract projects not known at the time the IRP was
published
• Other non-IRP investments common to all jurisdictions that are ongoing, for
example:
— Enterprise technology projects & programs
— Corporate facilities capital maintenance and improvements
Result: Avista holds quarterly meetings with OPUC Staff where
information such as this is discussed. This list of projects was also
formally presented to TAC members during the TAC 4 meeting in June
2024. Please refer to for a full listing of projects Avista is
currently monitoring.
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Chapter 11: Action Plan
Oregon (OPUC-Actions)
1. For the IRP Update the Company should update the load forecast with a GCM
downscaling methodology using Multivariate Adaptive Constructed Analogs as
employed by Oregon State University's Institute of Natural Resources.
(Recommendation 2)
Result: Avista utilized the MACA downscaling data for RCP 4.5 and 8.5 in
addition to blending the two for an RCP 6.5 weather future. This is
discussed in detail in ;hapter 3.
2. New program offered by ETO for interruptible customers in 2023 to save 15,000
therms. (Recommendation 3)
Result: Energy Trust of Oregon helped interruptible customers save 66
therms in 2023. The second year of the of the program offering in 2024
resulted in preliminary savings of 122,603 therms of natural gas saved
and will be finalized in their annual report.
3. Engage Oregon stakeholders to explore additional new offerings for interruptible,
transport, and low-income customers to work towards identified savings of 375,000
therms in 2024, 381,000 therms in 2025 and 371 ,000 therms in 2026.
(Recommendation 4)
Result. Energy Trust of Oregon has offered energy efficiency programs to
Avista interruptible customers since 2023. Avista continued to offer its low-
income energy efficiency program through the Community Action
Agencies for whole home retrofits. The Company began providing ETO
data in 2023 that indicates customers that participate in bill assistance so
that energy efficiency programs can be targeted to these customers. The
data received from ETO does not contain Account or Customer ID
number, so the Company is unable to fully verify low-income participation
and is working with ETO to update data received in 2025. Preliminary
2024 savings for interruptible and low-income programs totaled 126,500
therms with ETO low-income targeted efforts estimated at 23,949 therms.
The Company began standing-up an Equity Advisory Group in 2024 to
gain insights to help reduce customer energy burden through low-income
programs. Currently, a low-income whole home energy efficiency program
is being designed with ETO, and Bidgely Home Energy Reports will be
launched in 2025 to educate residential customers about how they use
energy and energy efficiency programs available to reduce usage.
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Chapter 11: Action Plan
4. Include the modeling of all relevant distribution system costs and capacity costs,
including additional projects that would be needed in high load scenarios as well as
costs that would not be incurred in lower load scenarios. (Recommendation 5)
Result: Avista included distribution cost estimates for current projects
anticipated to be needed in the next 5 years and are included in the
avoided costs and will include these costs in NPA analysis going forward.
It is difficult to model distribution level capacity and costs in a resource
selection model as pressure, needed capacity and cost increase are
difficult to estimate.
5. Avista work with the TAC to develop additional scenarios and sensitivities for the next
IRP, including for example: greater price variation for low carbon resources, high cost
for low carbon resources, omission of any highly uncertain resource, or utilization of
only existing resources. (Recommendation 6)
Result:Avista requested assistance and input beginning in TAC 2 in April
2024. Each meeting had space for feedback prior to the individual
presentations prepared with this topic discussed throughout the process.
Feedback was given by the TAC members and included in the analysis
included in this document.
6. Avista should update its distribution system planning practices and its future IRP
processes as outlined in Attachment C. (Expectation 22)
Result:Avista has updated its planning practices as discussed in :hapter
10.
7. ETO identified 546,000 therms in the 2023 IRP verses 427,000 therms of planned
savings in the 2023 ETO Budget and Action Plan. Avista will work with the ETO to
meet the IRP gross savings target of 568,000 therms in 2024, 590,000 therms in 2025
and 614,000 therms in 2026.
Result. Avista fully funded ETO's board approved budget in 2023 Budget
and Action Plan. The budget was increased in September 2024 due to the
programs performing better than expected. ETO saved 446,880 therms in
2023 and 477,906 therms in 2024.
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Chapter 11: Action Plan
2025-2026 Action Plan
1. Purchase Community Climate Investments for compliance to the Climate
Protection Plan for years 2025, 2026, 2027, 2028 and 2029 to comply with
emission reduction targets.
2. Avista will work with ETO to meet IRP gross savings target of 463,410 therms in
2026.
3. Engage Oregon's stakeholders to explore additional new offerings for
interruptible, transport, and low-income customers to work towards identified
savings of 147,250 therms in 2026.
4. Acquire all estimated potential energy efficiency savings for Idaho and
Washington.
5. In Washington purchase allowances or offsets for compliance to the Climate
Commitment Act for years 2025, 2026, 2027 and 2028 to comply with emissions
reduction targets.
6. Release an annual RFP to investigate options of acquiring the necessary amount
of RNG chosen in the PRS in 2030 of 1.184 million dekatherms.
7. Investigate adding liquified natural gas storage to improve resiliency in the North
Idaho/Eastern Spokane region.
8. Investigate carbon capture technologies for further understanding of processes
and costs needed for capturing and removal of carbon in large industry and direct
air capture.
9. Perform at least two NPA analysis for Washington in 2025 and 2026.
10.Perform an NPA analysis for any distribution project with an estimated cost
greater than $1 million in Oregon.
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