20230331Avista 2021 Natural Gas IRP.pdf

Ahnsm
Avista Corp.
1411 East Mission P.O.Box 3727
Spokane.Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
March 31,2023
Jan Noriyuki,Secretary
Idaho Public Utilities Commission
11331 W.Chinden Blvd.Bldg.8,Ste.201-A
Boise,Idaho 83714
RE:Case No.AVU-G-23-_g-Avista Utilities 2023 Natural Gas Integrated Resource Plan
Dear Ms.Noriyuki:
Avista Corporation d/bla/Avista Utilities,hereby submits for filing with the Commission its final
2023 Natural Gas Integrated Resource Plan (IRP).Supporting documents can be found on our
website at https://mvavista.com/about-us/integrated-resource-planning.
If you have any questions regarding this filing,please contact Tom Pardee at 509-495-2159.
Sincerely,
Is/stuuae &gu
Shawn Bonfield
Sr.Manager of Regulatory Strategy &Policy
509-434-6502
shawn.bonfield@ avistacorp.com
CASE NO. AVU-G-23-03
2 0 2 3
Natural Gas Integrated
Resource Plan

Safe Harbor Statement

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

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

Production Credits

Primary Natural Gas IRP Team
Name Title Contribution
James Gall Manager of Integrated Resource Planning IRP Core Team
Tom Pardee Natural Gas Planning Manager IRP Core Team
Michael Brutocao Natural Gas Analyst IRP Core Team
John Lyons Sr. 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
Ryan Finesilver Mgr. of Energy Efficiency, Planning & Analysis Energy Efficiency
Lisa McGarity Energy Efficiency Program Manager Oregon Energy Efficiency
Leona Haley Energy Efficiency Program Manager Demand Response
Terrence Browne Sr. System Planning Engineer Gas Engineering
Justin Dorr Natural Gas Resources Manager Power Supply

Natural Gas IRP Contributors
Name Title Contribution
Scott Kinney VP of Energy Resources Power Supply
Kevin Holland Director of Energy Supply Power Supply
Clint Kalich Sr. Manager of Resource Analysis Power Supply
Shawn Bonfield Sr. Manager of Regulatory Policy Regulatory
Amanda Ghering Regulatory Affairs Analyst Regulatory
Annie Gannon Communications Manager Communications
Mary Tyrie Manager Corporate Communications Communications
Jeff Webb Manager of Gas Design, Measuring and 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]

Table of Contents

Avista Corp 2023 Natural Gas IRP

i
Table of Contents

1. Introduction and Planning Environment ..................................................................... 1-1
Customers ................................................................................................................................ 1-3
Integrated Resource Planning .................................................................................................. 1-5
Planning Model ......................................................................................................................... 1-8
Planning Environment .............................................................................................................. 1-9
2. Demand Forecasts ........................................................................................................ 2-1
Demand Areas ......................................................................................................................... 2-1
Customer Forecasts ................................................................................................................. 2-1
Electrification of Natural Gas Customers ................................................................................. 2-3
Use-per-Customer Forecast ..................................................................................................... 2-4
Weather Forecast ..................................................................................................................... 2-6
Peak Day Design Temperature ................................................................................................ 2-9
Load Forecast ........................................................................................................................ 2-17
Scenario Analysis ................................................................................................................... 2-22
Alternative Forecasting Methodologies .................................................................................. 2-23
Key Issues .............................................................................................................................. 2-23
3. Demand Side Resources .............................................................................................. 3-1
Avoided Cost ............................................................................................................................ 3-1
Idaho and Washington Conservation Potential Assessment ................................................... 3-3
Pursuing Cost-Effective Energy Efficiency ............................................................................... 3-3
Washington and Idaho Energy Efficiency Potential ................................................................. 3-4
Demand Response ................................................................................................................. 3-10
Building Electrification ............................................................................................................ 3-14
4. Current Resources and New Resource Options ........................................................ 4-1
Natural Gas Commodity Resources ......................................................................................... 4-1
Transportation Resources ........................................................................................................ 4-8
Storage Resources ................................................................................................................. 4-13
Incremental Supply-Side Resource Options .......................................................................... 4-14
Alternative Fuel Supply Options ............................................................................................. 4-16
Project Evaluation - Build or Buy ............................................................................................ 4-18
Avista’s Natural Gas Procurement Plan ................................................................................. 4-30
Market-Related Risks and Risk Management ........................................................................ 4-31
5. Policy Issues .................................................................................................................. 5-1
Avista’s Environmental Objective ............................................................................................. 5-1
Natural Gas Greenhouse Gas System Emissions ................................................................... 5-1
Local Distribution Pipeline Emissions - Methane Study ........................................................... 5-3
State and Regional Level Policy Considerations ..................................................................... 5-3
Idaho ........................................................................................................................................ 5-3
Oregon ..................................................................................................................................... 5-4
Washington .............................................................................................................................. 5-8
Federal Legislation ................................................................................................................. 5-13
Customer Market study .......................................................................................................... 5-14
Key Takeaways ...................................................................................................................... 5-15
Equity Considerations ............................................................................................................ 5-18
6. Preferred Resource Strategy ........................................................................................ 6-1
PLEXOS® Planning Model ...................................................................................................... 6-1
Stochastic Analysis .................................................................................................................. 6-7
Resource Integration ................................................................................................................ 6-7
Carbon Policy Resource Utilization Summary ......................................................................... 6-8
Resource Utilization ............................................................................................................... 6-10
Demand and Deliverability Balance ....................................................................................... 6-14
New Resource Options and Considerations .......................................................................... 6-18
Energy Efficiency Resources ................................................................................................. 6-20
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Avista Corp 2023 Natural Gas IRP

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Preferred Resource Strategy (PRS) ....................................................................................... 6-22
Monte Carlo Risk Analysis ..................................................................................................... 6-29
Estimated Price Impacts ........................................................................................................ 6-32
7. Alternate Scenarios ....................................................................................................... 7-1
Alternate Demand Scenarios ................................................................................................... 7-1
Deterministic – Portfolio Evaluation and Scenario Results ...................................................... 7-1
Demand .................................................................................................................................... 7-2
PRS Scenarios ......................................................................................................................... 7-2
Electrification Scenarios ........................................................................................................... 7-5
Supply Scenarios ..................................................................................................................... 7-8
Other Scenarios ..................................................................................................................... 7-10
Washington Climate Commitment Act Allowances ................................................................ 7-12
Oregon Community Climate Investments .............................................................................. 7-13
Natural Gas Use ..................................................................................................................... 7-14
Synthetic Methane .................................................................................................................. 7-15
Renewable Natural Gas ......................................................................................................... 7-16
Emissions ............................................................................................................................... 7-17
Cost Comparison .................................................................................................................... 7-18
Regulatory Requirements ...................................................................................................... 7-21
8. Distribution Planning .................................................................................................... 8-1
Distribution System Planning ................................................................................................... 8-1
Network Design Fundamentals ................................................................................................ 8-2
Computer Modeling .................................................................................................................. 8-2
Determining Peak Demand ...................................................................................................... 8-3
Distribution System Enhancements ......................................................................................... 8-3
Conservation Resources .......................................................................................................... 8-5
Distribution Scenario Decision-Making Process ...................................................................... 8-5
Planning Results ...................................................................................................................... 8-8
Non-Pipe Alternatives............................................................................................................... 8-9
9. Action Plan ..................................................................................................................... 9-1
2021 IRP OPUC Recommendations ........................................................................................ 9-1
Avista’s 2021 IRP Action Items ................................................................................................ 9-4
2023-2024 Action Plan ............................................................................................................. 9-5

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Avista Corp 2023 Natural Gas IRP

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Table of Figures

Figure 1.1: Avista’s Natural Gas Service Territory ....................................................................... 1-1
Figure 1.2: Avista’s Natural Gas Customer Counts ...................................................................... 1-2
Figure 1.3: Firm Customer Mix ..................................................................................................... 1-3
Figure 1.4: 2021 Percent of Demand by Area and Class ............................................................. 1-4
Figure 1.5: Total System Average Daily Load .............................................................................. 1-5
Figure 1.6: Poll Question 1 ........................................................................................................... 1-7
Figure 1.7: Poll Question 2 ........................................................................................................... 1-8
Figure 2.1: Customer Forecast Scenarios .................................................................................... 2-3
Figure 2.2: Electrification Scenario Customer Forecast ............................................................... 2-4
Figure 2.3: Example Demand vs. Temperature – 2022 ............................................................... 2-4
Figure 2.4: Monthly Demand of Transport Customers (MMBTU) ................................................ 2-5
Figure 2.5: Usage Based on 2-year, 3-year, and 5-year Coefficient ............................................ 2-6
Figure 2.6: Impact of RCP 4.5 Temperature Data on Load Forecast .......................................... 2-9
Figure 2.7: Spokane Weather Station – Weather Planning Standard Comparison ................... 2-10
Figure 2.8: Spokane Historical Temperature Distribution........................................................... 2-11
Figure 2.9: Medford Historical Temperatures ............................................................................. 2-12
Figure 2.10: La Grande Historical Temperatures ....................................................................... 2-12
Figure 2.11: Klamath Falls Historical Temperatures .................................................................. 2-13
Figure 2.12: Roseburg Historical Temperatures ........................................................................ 2-13
Figure 2.13: Frequency of Peak Day Occurrences – Spokane .................................................. 2-15
Figure 2.14: Frequency of Peak Day Occurrences – Medford ................................................... 2-15
Figure 2.15: Frequency of Peak Day Occurrences – Roseburg ................................................ 2-16
Figure 2.16: Frequency of Peak Day Occurrences – Klamath Falls .......................................... 2-16
Figure 2.17: Frequency of near Peak Day Occurrences – La Grande ....................................... 2-17
Figure 2.18: System Demand – 1,000 Dth (500 Draws) ............................................................ 2-20
Figure 2.19: Idaho Demand – 1,000 Dth (500 Draws) ............................................................... 2-20
Figure 2.20: Oregon Demand – 1,000 Dth (500 Draws) ............................................................ 2-21
Figure 2.21: Washington Demand – 1,000 Dth (500 Draws) ..................................................... 2-21
Figure 3.1: Annual Avoided Cost (by jurisdiction) ........................................................................ 3-2
Figure 3.2: Winter Avoided Cost (by jurisdiction) ......................................................................... 3-2
Figure 3.3: Program Characterization Process .......................................................................... 3-11
Figure 3.4: Space Heat Efficiency by Degrees Fahrenheit and Fuel ......................................... 3-15
Figure 3.5: Energy Conversion Efficiency therms to kWh .......................................................... 3-16
Figure 3.6: Estimated Conversion Costs .................................................................................... 3-17
Figure 3.7: Electric Rate Assumption by Area by Class ............................................................. 3-18
Figure 3.8: Conversion Costs and Energy Costs for Space Heat .............................................. 3-19
Figure 3.9: Space Heat Levelized Costs by Area for Residential Electrification ........................ 3-20
Figure 3.10: Water Heat Levelized Costs by Area for Residential Electrification ...................... 3-20
Figure 3.11: Space Heat Levelized Costs by Area for Commercial Electrification .................... 3-21
Figure 3.12: Water Heat Levelized Costs by Area for Commercial Electrification ..................... 3-21
Figure 4.1: Monthly Index Prices .................................................................................................. 4-3
Figure 4.2: Henry Hub Forecasted Price (Nominal $/Dekatherm) ............................................... 4-5
Figure 4.3: Expected Price with Allocated Price Forecast ........................................................... 4-6
Figure 4.4: Henry Hub Forecasts for IRP Low/ Expected/ High Forecasted Price ...................... 4-7
Figure 4.5: Regional Price as a compared to the Henry Hub Price ............................................. 4-8
Figure 4.6: AECO - $ per Dth (500 Draws) .................................................................................. 4-8
Figure 4.7: Regional Pipeline and Storage Capacity .................................................................... 4-9
Figure 4.8: Direct-Connect Pipelines .......................................................................................... 4-11
Figure 4.9: Participants by State ................................................................................................ 4-19
Figure 4.10: Avista RNG Development and Procurement Decision Tree – Part 1 .................... 4-20
Figure 4.11: Avista RNG Development and Procurement Decision Tree – Part 2 .................... 4-21
Figure 4.12: RNG Price by Source (nominal $) .......................................................................... 4-23
Figure 4.13: Production Types of Hydrogen: .............................................................................. 4-24
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Figure 4.14: Green Hydrogen Cost Estimates ........................................................................... 4-25
Figure 4.15: Synthetic Methane cost estimates ......................................................................... 4-26
Figure 4.16: RNG Landfill RNG - $ per Dth (500 Draws) ........................................................... 4-27
Figure 4.17: Dairy RNG - $ per Dth (500 Draws) ....................................................................... 4-28
Figure 4.18: Food Waste RNG - $ per Dth (500 Draws) ............................................................ 4-28
Figure 4.19: Wastewater Treatment RNG - $ per Dth (500 Draws) ........................................... 4-29
Figure 4.20: Hydrogen (500 Draws) ........................................................................................... 4-29
Figure 4.21: Synthetic Methane - $ per Dth (500 Draws) ........................................................... 4-30
Figure 5.1: Oregon Customers Annual Emissions Compliance Cap ........................................... 5-5
Figure 5.2: Oregon Emissions by Class for 2022 ......................................................................... 5-5
Figure 5.3: Maximum Available CCI Compared to the Reduction Goal ....................................... 5-6
Figure 5.4: Community Climate Investment ($ per MTCO2e) ...................................................... 5-7
Figure 5.5: Business as Usual Emission Forecast vs. Utility Goal ............................................... 5-7
Figure 5.6: Climate Commitment Act Coverage ........................................................................... 5-9
Figure 5.7: Avista’s Estimated Annual Emissions Cap............................................................... 5-10
Figure 5.8: Emissions Reductions from Offset Projects ............................................................. 5-11
Figure 5.9: Expected CCA Allowance Prices ............................................................................. 5-12
Figure 5.10: Bill Increase and Carbon-Neutral or Carbon-Free Options .................................... 5-15
Figure 5.11: Importance of “Green” ............................................................................................ 5-16
Figure 5.12: An Increased Bill and Possible Actions from Customers ....................................... 5-17
Figure 5.13: Customer Concerns with Fuel Switching ............................................................... 5-17
Figure 6.1: PLEXOS® Idaho System Map ................................................................................... 6-2
Figure 6.2: PLEXOS® Washington System Map ......................................................................... 6-3
Figure 6.3: PLEXOS® Oregon System Map ................................................................................ 6-3
Figure 6.4: PLEXOS® Washington Transport Customer Map ..................................................... 6-4
Figure 6.5: PLEXOS® Oregon Transport Customer Map ............................................................ 6-4
Figure 6.6: Modeling Workflow Diagram ...................................................................................... 6-6
Figure 6.7: Total System Average Daily Load (Average, Minimum and Maximum) .................... 6-8
Figure 6.8: Carbon Legislation Sensitivities ................................................................................. 6-9
Figure 6.9: Existing Firm Transportation Resources .................................................................. 6-10
Figure 6.10: Average Demand Compared to Storage & Transport Rights for February 28th .... 6-15
Figure 6.11: Average Demand Compared to Storage & Transport Rights for December 20th . 6-15
Figure 6.12: Expected Peak Day Demand Compared to Storage & Transport Rights for February
28th ..................................................................................................................................... 6-16
Figure 6.13: Expected Peak Day Demand Compared to Storage & Transport Rights for
December 20th .................................................................................................................. 6-16
Figure 6.14: Washington Emissions Forecast Compared to CCA Cap...................................... 6-17
Figure 6.15: Emissions Forecast Compared to CPP Cap .......................................................... 6-17
Figure 6.16: Resource Options and Costs in PLEXOS Model ................................................... 6-19
Figure 6.17: Idaho Preferred Resource Strategy ....................................................................... 6-23
Figure 6.18: Natural Gas Basin Least Cost - Idaho .................................................................... 6-23
Figure 6.19: Oregon Preferred Resource Strategy .................................................................... 6-24
Figure 6.20: Natural Gas Basin Least Cost – Oregon ................................................................ 6-24
Figure 6.21: Community Climate Investment Quantity – (MTCO2e) .......................................... 6-26
Figure 6.22: Washington Preferred Resource Strategy ............................................................. 6-27
Figure 6.23: Natural Gas Basin Least Cost - Washington ......................................................... 6-27
Figure 6.24: CCA Allowances/Offsets Quantity Needed (MTCO2e) .......................................... 6-29
Figure 6.25: System Annual Costs – 1,000 of $ (500 Draws) .................................................... 6-30
Figure 6.26: Idaho Annual Costs – 1,000 of $ (500 Draws) ....................................................... 6-30
Figure 6.27: Oregon Annual Costs – 1,000 of $ (500 Draws) .................................................... 6-31
Figure 6.28: Washington Annual Costs – 1,000 of $ (500 Draws) ............................................. 6-31
Figure 6.29: Residential Price Impact ($ of therm) ..................................................................... 6-32
Figure 6.30: Commercial Price Impact ($ per therm) ................................................................. 6-32
Figure 6.31: Industrial Price Impact ($ per therm) ...................................................................... 6-33
Figure 6.32: Transport Price Impact ($ per therm) ..................................................................... 6-33
Figure 7.1: Demand by Scenario .................................................................................................. 7-2
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Avista Corp 2023 Natural Gas IRP

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Figure 7.2: PRS Scenarios - Annual System Costs ..................................................................... 7-3
Figure 7.3: Annual Electrification Levelized Costs by Source ...................................................... 7-6
Figure 7.4: Electrification as a Demand-Side Resource by Scenario and State .......................... 7-8
Figure 7.5: Supply Scenarios vs PRS - Annual System Costs .................................................... 7-9
Figure 7.6: Other Scenarios vs PRS - Annual System Costs .................................................... 7-11
Figure 7.7: Allowance Demand by Scenario – Washington CCA .............................................. 7-13
Figure 7.8: CCI Demand by Scenario – Oregon CPP ................................................................ 7-14
Figure 7.9: Natural Gas Supply .................................................................................................. 7-15
Figure 7.10: Annual Synthetic Methane Volumes by 2045 ........................................................ 7-15
Figure 7.11: Oregon RNG Volumes Across Scenarios .............................................................. 7-16
Figure 7.12: Washington RNG Volumes Across Scenarios ....................................................... 7-17
Figure 7.13: System Emissions by Scenario by 2030 ................................................................ 7-18
Figure 7.14: PRS Alternative Scenario Cost Comparison .......................................................... 7-19
Figure 7.14: Residential Customer Price Impact ($ per dekatherm) .......................................... 7-19
Figure 7.14: Commercial Customer Price Impact ($ per dekatherm) ......................................... 7-20
Figure 7.14: Industrial Customer Price Impact ($ per dekatherm) ............................................. 7-20
Figure 7.14: Transport Only Customer Price Impact ($ per dekatherm) .................................... 7-20
Figure 8.1: Distribution Scenario Process .................................................................................... 8-7

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Avista Corp 2023 Natural Gas IRP

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Table of Tables

Table 1.1: TAC Member Participation .......................................................................................... 1-6
Table 1.2: Summary of Changes from the 2021 IRP ................................................................. 1-10
Table 2.1: Geographic Demand Classifications ........................................................................... 2-1
Table 2.2: Customer Growth Scenarios ....................................................................................... 2-2
Table 2.3: Comparison of Temperature Increases by Representative Concentration Pathway .. 2-8
Table 2.4: Peak Day Design Temperature ................................................................................. 2-11
Table 2.5: Example of Monte Carlo Weather Inputs – Spokane ................................................ 2-14
Table 2.6: Load Forecast (Thousand Dekatherms) .................................................................... 2-18
Table 2.7: Peak Day Load Forecast (Thousand Dekatherms) ................................................... 2-19
Table 2.8: Demand Scenarios .................................................................................................... 2-22
Table 2.9: Annual Demand – 2023 IRP Scenarios (000 dth) ..................................................... 2-23
Table 3.1: Cost Effectiveness Test ............................................................................................... 3-4
Table 3.2: Washington Energy Efficiency Potential by Case (dekatherms) ................................. 3-5
Table 3.3: Idaho Energy Efficiency Potential by Case (dekatherms) ........................................... 3-5
Table 3.4: Washington 2024-2025 Conservation Target by Sector, (therms) .............................. 3-6
Table 3.5: Idaho 2024-2025 Conservation Target by Sector, (therms) ........................................ 3-6
Table 3.6: Summary of Oregon Low-Income Energy Efficiency Potential ................................... 3-8
Table 3.7: Summary of Oregon Interruptible Industrial Energy Efficiency Potential .................... 3-8
Table 3.8: Summary of Oregon Interruptible Commercial Energy Efficiency Potential ................ 3-9
Table 3.9: Summary of Oregon Transport Industrial Energy Efficiency Potential ........................ 3-9
Table 3.10: 20-Year Cumulative Savings Potential by Type (Millions of Therms) ..................... 3-10
Table 3.11: NGDR Program Options by Market Segment ......................................................... 3-11
Table 3.12: NGDR Program Steady-State Participation Rates .................................................. 3-13
Table 3.13: System Program Cost and Potential ....................................................................... 3-14
Table 4.1 : Price Blend Methodology............................................................................................ 4-6
Table 4.2: Firm Transportation Resources Contracted (Dth/Day) .............................................. 4-10
Table 4.3: Carbon Intensity ........................................................................................................ 4-16
Table 4.4: All resource price comparison $/Dth ......................................................................... 4-26
Table 5.1: Avista Specific LDC Natural Gas Emissions ............................................................... 5-2
Table 5.2: Global Warming Potential (GWP) in CO2 Equivalent ................................................. 5-2
Table 5.3: National Greenhouse Gas Pricing Forecast ................................................................ 5-4
Table 6.1: New Supply-Side and Demand-Side Resource Options ........................................... 6-18
Table 6.2: Annual Demand Served by Energy Efficiency .......................................................... 6-21
Table 6.3: Average Daily Demand Served by Energy Efficiency ............................................... 6-21
Table 6.4: Average Daily Resource Quantities by Year ............................................................. 6-25
Table 6.5: Average Daily Resource Quantities by Year – Washington ...................................... 6-28
Table 7.1: 2023 IRP Scenarios ..................................................................................................... 7-1
Table 7.2: PRS Scenarios - Portfolio Selections .......................................................................... 7-4
Table 7.3: Electrification Scenarios - Portfolio Selections ............................................................ 7-7
Table 7.4: Supply Scenarios – Portfolio Selection ..................................................................... 7-10
Table 7.5: Other Scenarios – Portfolio Selection ....................................................................... 7-12
Table 8.1: High Pressure - Distribution Planning Capital Projects ............................................... 8-9
Table 8.2: City Gate Station Upgrades ......................................................................................... 8-9
Table 9.1: Oregon Distribution Projects ....................................................................................... 9-5

Executive Summary
Avista Corp 2023 Natural Gas IRP i

Executive Summary

Avista’s 2023 Natural Gas Integrated Resource Plan (IRP) identifies a Preferred
Resource Portfolio (PRS) to meet system energy demand and emissions compliance in
Washington under the Climate Commitment Act (CCA) and Oregon under Climate
Protection Plan (CPP). Avista considered resource capacity needs on a peak day
combined with weather futures to consider a warming trend and its impact on demand.
The total system load is illustrated in Figure 1 by month to help depict the seasonality of
firm customer demand on the natural gas distribution infrastructure.

Figure 1: Total System Average Daily Load (Average, Minimum and Maximum)

Customer forecasts are increasingly difficult to model based on a variety of rules and
codes passed since the 2021 IRP. In Washington, a building code update will go into
effect on July 1, 2023, requiring heat pump technology for space and water heating in all
new residential and commercial buildings. Line extension programs to assist customers
with natural gas 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, fourteen scenarios
were developed to consider a range of different futures and resource selections. Avista
is still long transport rights, consistent with prior IRP expectations. Peak Day criteria is
important as it protects our customers and their structures during extreme weather.

Emissions compliance under the CCA and CPP tells a different story for resource need.
Greenhouse gas emissions compliance considers program constraints of the CCA and
CPP, plus these regulations require planning for transport customers where past plans
did not. In both Figure 2 and Figure 3, equivalent emissions from Firm customers and
transport customers can be found in the stacked bar chart with the cap for the respective
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Executive Summary
Avista Corp 2023 Natural Gas IRP ii

program as a line. These charts clearly show noncompliance if no actions are taken to
offset emissions or other options per program rules, where the total emissions in the blue
and green bars exceed the cap shown in orange. These shortages occur in 2023 and
continue through the end of the study in 2045.

Figure 2: Washington Emissions Forecast Compared to CCA Cap

Figure 3: Emissions Forecast Compared to CPP Cap

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Executive Summary
Avista Corp 2023 Natural Gas IRP iii

Idaho Preferred Resource Strategy
The Idaho PRS continues to utilize the least cost natural gas basin, and storage,
combined with energy efficiency to meet energy demand as illustrated in Figure 4. Natural
gas will be acquired on a least cost basis from the available hubs.

Figure 4: Idaho Preferred Resource Strategy

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Executive Summary
Avista Corp 2023 Natural Gas IRP iv

Oregon Preferred Resource Strategy
Oregon’s PRS has drastically changed as compared to the 2021 IRP. Changes adhere
to the new environmental goals of the CPP and the estimated energy demand. In the
near-term, the new resource need is acquired via a combination of RNG from Landfill Gas
(LFG), Wastewater Treatment Plants (WWTP), energy efficiency, Community Climate
Investments (CCIs), and conventional natural gas. Synthetic methane is added to the
resource mix beginning in the 2030’s, as illustrated in Figure 5. In each figure, the dark
blue area at the bottom of the chart depicts natural gas with no emissions instrument for
compliance, essentially the cap of the CPP.

Figure 5: Oregon Preferred Resource Strategy

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RNG - WWTP Natural Gas With CCI DSM
Executive Summary
Avista Corp 2023 Natural Gas IRP v

Washington Preferred Resource Strategy
Washington’s PRS has also changed dramatically from the 2021 IRP. The CCA has
introduced a cap-and-trade program with the ability to cover emissions with an allowance
or offset. Allowance and offset prices may drive a different PRS than the one illustrated
in Figure 6. The range of allowance prices for 2023 is $22 to $82 USD. The PRS shows
conventional natural gas and energy efficiency as the primary energy source options until
the end of the study horizon (2044), when synthetic methane is chosen. The darker blue
area in the chart is the CCA program cap and would not require any type of program
instruments. The lighter blue area represents natural gas as an energy source, requiring
an offset or an allowance as it is above the cap. Natural gas will continue to be procured
from the least cost supply basin.

Figure 6: Washington Preferred Resource Strategy

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Synthetic Methane DSM
Executive Summary
Avista Corp 2023 Natural Gas IRP vi

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Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-1

1. Introduction and Planning Environment

Avista is an investor-owned utility involved in the production, transmission, and
distribution of natural gas and electricity, as well as other energy-related businesses.
Avista, founded in 1889 as Washington Water Power, has been providing reliable,
efficient, and reasonably priced energy to customers for over 130 years.

Avista entered the natural gas business with the purchase of Spokane Natural Gas
Company in 1958. In 1970, it expanded into natural gas storage with Washington Natural
Gas (now Puget Sound Energy) and El Paso Natural Gas (its interest subsequently
purchased by Northwest Pipeline) to develop the Jackson Prairie natural gas
underground storage facility 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.

Figure 1.1: Avista’s Natural Gas Service Territory

Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-2

Figure 1.2: Avista’s Natural Gas Customer Counts

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:

• The North Division includes Avista’s eastern Washington and northern Idaho
service area. 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 546,0001 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 5,800 miles in the distribution system in Washington
and 3,300 miles in Idaho. The North Division receives natural gas at more than 40
connection points along interstate pipelines for distribution to over 270,000
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, is the largest single area served in this division with a regional population
of approximately 312,000. The South Division consists of approximately 15 miles
of natural gas transmission main and 3,700 miles of distribution pipelines. Avista
receives natural gas at more than 20 connection points along interstate pipelines
and distributes it to nearly 106,000 customers.

1 https://www.census.gov/quickfacts/fact/table/spokanecountywashington,WA/PST045221
Residential, 340,000
Commercial -Firm,
36,600
Commercial -Interruptible, 25
Industrial -Firm, 185
Transport -
Commercial, 28
Transport -Industrial, 52
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-3

Customers
Avista provides natural gas services to both core and transportation-only customer
classes. Core or retail customers purchase natural gas directly from Avista with delivery
to their home or business under a bundled rate. Core customers on firm rate schedules
are entitled to receive any volume of natural gas they require. Some core customers are
on interruptible rate schedules. These customers pay a lower rate than firm customers
because their service can be interrupted. Interruptible customers are not considered in
peak day IRP planning.

Transportation-only customers purchase natural gas from third parties who deliver the
purchased gas to our distribution system. Avista delivers this natural gas to its business
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 require Avista to comply for these emissions for the interruptible and
transport customers. These new programs are discussed in Chapter 5 with resource
selection in Chapter 6.

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

ID -RES, 84,000
ID -FIRM COM, 9,600
ID -FIRM IND, 70 ID -COM TPORT, 3
ID -IND TPORT, 5
OR -RES, 95,000
OR -FIRM COM, 12,000
OR -INT COM, 22
OR -FIRM IND, 25
OR -INT IND, 22
OR -COM TPORT, 9
OR -IND TPORT, 24
WA -RES, 161,000
WA -FIRM COM, 15,000
WA -INT COM, 3
WA -FIRM IND, 90
WA -COM TPORT, 16
WA -IND TPORT, 23
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-4

The customer mix is found mostly in the residential and commercial accounts on an
annual volume basis (Figure 1.4). Volume consumed by core industrial customers is not
significant to the total, partly because most industrial customers in Avista’s service
territories are transportation-only customers. These customers, however, will require a
compliance mechanism or alternative fuels to meet emissions targets.

Figure 1.4: 2021 Percent of Demand by Area and Class

The seasonal nature of weather in the Pacific Northwest can drastically alter the amount
of energy demanded from the natural gas system (Figure 1.5). Industrial demand, which
is typically not weather sensitive, has very little seasonality. However, the La Grande
service territory has several industrially classified agricultural processing facilities
producing a late summer seasonal demand spike.

01 RESIDENTIAL, 40%
21 FIRM COMMERCIAL, 22%31 FIRM-INDUSTRIAL, 1%
91 COMMERCIAL-TRANS OF GAS FOR OTHERS, 1%
92 INDUSTIAL-TRANS OF GAS FOR OTHERS, 35%
01 RESIDENTIAL, 38%
21 FIRM
COMMERCIAL, 24%22 INTERRUPTIBLE COMMERCIAL, 3%
31 FIRM-INDUSTRIAL, 0%
41 INTERRUPTIBLE-INDUSTRIAL, 7%
91 COMMERCIAL-TRANS OF GAS FOR OTHERS, 3%
92 INDUSTIAL-
TRANS OF GAS FOR OTHERS, 24%
01 RESIDENTIAL, 43%
21 FIRM COMMERCIAL, 26%22 INTERRUPTIBLE COMMERCIAL, 0%
31 FIRM-INDUSTRIAL, 1%
91 COMMERCIAL-TRANS OF GAS FOR OTHERS, 10%
92 INDUSTIAL-TRANS OF GAS FOR OTHERS, 18%
93 INTERDEPARTMENT-REV FROM TRANSP OF GAS, 2%
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-5

Figure 1.5: Total System Average Daily Load

Integrated Resource Planning
Avista’s IRP involves a comprehensive analytical process to ensure the core firm
customers receive long-term reliable natural gas service in extreme weather. The IRP
evaluates, identifies, and plans for the acquisition of an optimal combination of existing
and future resources using expected costs and associated risks to meet stage
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;
• Meets Washington, Idaho, and Oregon regulations, commission orders,
environmental programs and other applicable guidelines.

Avista’s IRP Process Considerations
• Customer growth and usage;
• Weather planning standard;
• Energy Efficiency opportunities;
• Existing and potential supply-side resource options;
• Current and potential legislation/regulation;
• Greenhouse gas emissions reductions and compliance mechanisms;
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Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-6

• 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 five public TAC meetings to facilitate stakeholder involvement in the
2023 IRP. The first meeting convened in February 2022 and the last meeting occurred in
December 2022. Each meeting included a broad spectrum of stakeholders. The meetings
focused on specific planning topics, reviewing the progress of planning activities, and
soliciting input on IRP development and results. Avista appreciates the time and effort
TAC members contributed to the IRP process as they provided valuable input through
their participation. A list of these organizations can be found below (Table 1.1).

Table 1.1: TAC Member Participation

Cascade Natural Gas Northwest Energy Coalition Oregon Public Utility
Commission
Fortis Northwest Natural Gas Alliance of Western Energy
Consumers
Idaho Public Utilities
Commission Biomethane, LLC Washington State Office of the
Attorney General
Northwest Gas Association Washington Utilities and
Transportation Commission Citizens Utility Board of Oregon
Washington State
Department of Commerce
Northwest Power and
Conservation Council Energy Trust of Oregon
Intermountain Gas
Company Energy Strategies RNG Coalition
Lewis and Clark Law
School Eastern Washington University Applied Energy Group
Oregon Department of
Energy
San Francisco Bay Area
Planning and Urban Research
Association (SPUR)
DecisionWare Group

Public Meetings
Two public meetings were held on March 8th, 2023 at noon and 5 pm lasting an hour
each. In each meeting Avista reviewed the preferred resources selected in both the
electric and natural gas IRPs to meet energy demand and/or energy policy compliance.

An email was sent to TAC members and customers in all jurisdictions informing them of
the opportunity to participate and provide feedback. Avista also included a recorded video
of its resource planning process and resource strategies. During the public meeting,
summary level results by jurisdiction were presented to the participants. The public
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-7

meeting structure is important as one does not have to be versed in the technical side of
energy, statistics, math, chemistry, or other potential topics as discussed in TAC
meetings. 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 website2.

A set of five poll questions were asked to meeting participants surrounding topics
including emissions compliance pathways for natural gas, equity, demand response, and
ranking the overall importance of planning considerations when compared with a variety
of options valued in IRPs. The two poll questions directly related to natural gas are
illustrated in Figure 1.6 and 1.7.

Generally, participants were engaged in the conversation representing many viewpoints
of how Avista serves its customers. A common theme of concerns are related to cost
impacts of environmental policy, how other states policies effect non-participating states,
and whether or not natural gas will continue to be available.

Figure 1.6: Poll Question 1

2 https://www.myavista.com/about-us/integrated-resource-planning
50%
24%
21%
5%
How should Avista meet state policy objectives to lessen greenhouse
gas emissions on the natural gas system?
Invest in renewable or synthetic
natural gas
Pay state "taxes or fees" to continute
to use natural gas
Use ratepayer funds to subsidize
building electrification
Use taxpayer funds to subsidize
building electrification
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-8

Figure 1.7: Poll Question 2

Regulatory Requirements
Avista submits a natural gas IRP to the public utility commissions in Idaho, Oregon, and
Washington every two years as required by state law or rule. There is a statutory
obligation to provide reliable natural gas service to customers at rates, terms, and
conditions that are fair, just, reasonable, and sufficient. Avista regards the IRP as a means
for identifying methodologies and processes for the evaluation of potential resource
options and as a process to establish an Action Plan for resource decisions. Ongoing
investigation, analysis, and research may result in determining alternative resources are
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 2023 IRP, Avista used the PLEXOS® planning model to perform
comprehensive natural gas supply planning and analysis in place of the old software from
ABB Sendout. PLEXOS®, from Energy Exemplar, provides unlimited flexibility in its ability
to run scenarios, constraints, variables, horizons, and environmental constraints. This
model uses a nodal and zonal analysis with:

• Customer growth and customer natural gas usage to form demand forecasts;
• Existing and potential transportation and storage options and associated costs;
• Existing and potential natural gas supply availability and pricing;
• Revenue requirements on all new asset additions;
• Weather assumptions; and
• Conservation.

45%
30%
23%
3%
What would you prioritize among the choices below, acknowledging they
are all important?
A reliable system
Environmental issues
Affordability
Equitable investments
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-9

Avista incorporated stochastic modeling in PLEXOS® to incorporate weather and price
uncertainty. Some examples of the types of stochastic analysis provided include:

• Stochastics futures where five future scenarios are solved simultaneously with a single set of
resource selections;
• Price and weather probability distributions;
• Probability distributions of costs (i.e. system costs, storage costs, commodity costs); and
• Resource mix (optimally sizing a contract or asset level of competing resources).

These computer-based planning tools were used to develop the 20-year best cost/risk
resource portfolio plan to serve customers.

Planning Environment
Even though Avista publishes an IRP every two years, the process is ongoing with new
information and industry related developments 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 Mexico exports as well as industrial uses. One of the most
prominent risks in the IRP involves policies meant to decrease the use of natural gas as
outlined in Chapter 5. However, there is uncertainty about the timing and size of those
policy decisions.

IRP Planning Strategy
Planning for an uncertain future requires robust analysis encompassing a wide range of
possibilities. Avista has determined 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;
• 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, lease-cost, long-term solutions. The following chart
summarizes significant changes from the 2021 IRP (Table 1.2).

Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-10

Table 1.2: Summary of Changes from the 2021 IRP

Subject Area 2023 Natural Gas IRP 2021 Natural Gas IRP
Demand System Growth 1.10% 1.00%
Demand System Growth
Washington building code
requirements for residential and
commercial homes to use a heat
pump for space and water heat
beginning in July 2023
None
Demand
Weather and
Design Day
Peak
99% probability of a temperature
occurring based on the coldest
temperature each year for the past
30 years combined with weather
forecasted temperatures and
trended from the historic peak day
99% probability of a
temperature occurring
based on the coldest
temperature each year for
the past 30 years
Demand
Weather and
Design Day
Peak
Climate Change future weather
predictions incorporated into
analysis
20 year rolling average
weather utilized
Demand Energy
Efficiency Cumulative Savings over 20 years: Cumulative Savings over 20
years:
Demand Energy
Efficiency ID: 12.7 Million Therms ID: 21.4 Million Therms
Demand Energy
Efficiency OR: 16.1 Million Therms OR: 14.8 Million Therms
Demand Energy
Efficiency WA: 25.3 Million Therms WA: 37.7 Million Therms
Demand Energy
Efficiency
A higher price curve with less
potential
A lower price curve and
slightly less conservation
potential
Demand Energy
Efficiency CPA for Demand Response (DR) None
Demand Energy
Efficiency
CPA for Transport Customers in
Oregon and Washington None
Demand Energy
Efficiency
CPA for Low Income Customers in
Oregon None
Demand Energy
Efficiency
ID: National Carbon Tax beginning
in 2030 ($12.00 - $62.08) per
MTCO2e
No Program or Cost
Demand Energy
Efficiency
OR: Social Cost of Carbon @ 2.5%
discount rate ($92.68 - $185.07)
per MTCO2e
California Cap and Trade -
($15.83 – $97.90)
Demand Energy
Efficiency
WA: Social Cost of Carbon @ 2.5%
discount rate ($92.68 - $185.07)
per MTCO2e
WA – Social Cost of Carbon
@ 2.5% discount rate
($79.86 - $158.06)
Supply Energy Prices Synthetic Methane Evaluated None
Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-11

Supply Energy Prices Electrification by Area and End Use
Evaluated None
Supply Energy Prices RNG by type evaluated combined
with volumetric expectations None
Supply Energy Prices A higher price curve at $4.50 / Dth
levelized cost in real 2022 US $
A lower price curve at $3.73
/ Dth levelized cost in real
2019 US $
Policy CCA Climate Commitment Act (CCA) -
Washington No Program
Policy CCA Allowance Floor Price of CCA No Program
Policy CCA Allowance Ceiling Price of CCA No Program
Policy CCA Emissions Compliance to CCA No Program
Policy CPP Climate Protection Plan (CPP) -
Oregon No Program
Policy CPP Community Climate Investment
(CCI) No Program
Policy CPP Emissions Compliance to CPP No Program
Policy IRA Inflation Reduction Act included No Program
Scenario Resource
Shortage
Due to the new climate policies in
Oregon and Washington all
scenarios require new resources.
There are two cases where
resource deficiencies occur,
the High Growth/Low Price
scenario and the Carbon
Reduction scenario. The
High Growth/Low Price
scenario is solved by
adding RNG landfill within
the city gate. The Carbon
Reduction scenario looks to
reduce emissions and Dairy
RNG provides the greatest
amount of carbon
intensity/carbon capture of
RNG sources.
Scenario New Scenario Electrification Scenarios None
Scenario New Scenario Hybrid Scenario None

Chapter 1: Introduction and Planning Environment
Avista Corp 2023 Natural Gas IRP 1-12

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Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-1

2. Demand Forecasts

The IRP process 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 PLEXOS® model (Table 2.1). These demand areas are aggregated into five
service territories and further summarized as North or South divisions for presentation
throughout this IRP.

Table 2.1: Geographic Demand Classifications

Demand Area Service Territory Division
Washington NWP Spokane North
Washington GTN Spokane North
Washington Both Spokane North
Idaho NWP Coeur D' Alene North
Idaho GTN Coeur D' Alene North
Idaho Both Coeur D' Alene North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Roseburg South
Roseburg Medford/Roseburg South
Klamath Falls Klamath Falls South
La Grande La Grande South

Customer Forecasts
Avista’s customer base includes firm residential, commercial, and industrial categories.
For each of the customer categories, Avista develops customer forecasts incorporating
national economic forecasts and 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. A detailed
description of the customer forecast is found in Appendix 2.1. 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.

The customer forecast in the 2023 IRP assumes growth based on historic trends. These
trends were evaluated against electrification end uses to consider conversion based on
economics. A price elasticity was not incorporated in this analysis so there may be
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-2

additional movement from natural gas customers to electric end uses simply due to
increases in price to comply with climate programs.

Forecasting customer growth is an inexact science, so it is important to consider different
forecasts. Two alternative growth forecasts were developed for this IRP. Avista developed
High and Low Growth forecasts to provide potential paths and test resource adequacy.
Appendix 2.1 contains a description of how these alternatives were developed. However,
it is important to understand these forecasts reflect the “status quo” and do not fully reflect
emerging natural gas connection restrictions in Washington and Oregon. Avista added a
customer scenario to measure building electrification to consider potential impacts based
on movement from natural gas to an alternative fuel source. After the completion of this
forecast Washington added restrictions to new residential and commercial natural gas
connects through new construction building codes. It is unclear at this point how those
new codes will impact the accumulation of new gas customers. Avista will carefully follow
implications for these codes and incorporate a forecast in the 2025 IRP to better reflect
these fundamental changes.

Table 2.2 shows the three customer growth forecasts. The expected case customer
counts are lower than the last 2021 IRP. Lower customer growth relates to lower
forecasted demand from both the average and peak day perspective. Detailed customer
count data by region and class for all three scenarios is in Appendix 2.2. In comparison
to Avista’s 2021 IRP, the base forecast for customer growth increases by just over 22,000
new customers. This sharp change reflects (1) a stronger than expected recovery from
the 2020 pandemic induced recession; (2) stronger than expected in-migration, especially
to our Washington and Idaho service territories; and (3) higher population growth
forecasts compared to the 2021 IRP, especially in Avista’s Washington and Idaho service
territories. Rules and policy are changing quickly with natural gas usage as discussed in
Chapter 5. In consideration of these fundamental changes in Oregon and Washington, a
scenario for electrification was developed to consider a lower than expected customer
growth based on historic trends. Figure 2.1 illustrates the average annual customer
forecasts used in the 2023 IRP.

Table 2.2: Customer Growth Scenarios

Variable Base Growth High Growth Low Growth
Customers 1.1% 1.4% 0.7%
Population 0.7% 0.9% 0.3%

Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-3

Figure 2.1: Customer Forecast Scenarios

Electrification of Natural Gas Customers
In 2022, Washington’s1 Building Council passed new commercial and residential
construction building code changes to essentially require heat pumps for space and water
heat beginning July 1, 2023. For residential buildings, codes do not require a specific fuel
source if heat pump technology is utilized. Oregon does not currently have any codes or
policies requiring building electrification.

To help quantify a loss of demand on the natural gas system, a building electrification
scenario was created to consider a loss of customers as compared to the expected
number of customers in Oregon and Washington with an average reduction of 98% from
the prior year for the same month, by area and class as illustrated in Figure 2.2. In total
an estimated 33% reduction in residential customers occurs in both jurisdictions by 2045.
This equates to a loss of natural gas system demand of 6.9 million dekatherms per over
the 23-year timeframe. Further discussion of this scenario is discussed in Chapter 7.

1 Digital Codes (iccsafe.org)
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High Expected Electrification
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-4

Figure 2.2: Electrification Scenario Customer Forecast

Use-per-Customer Forecast
The goal for a use-per-customer forecast is to develop base and weather sensitive
demand coefficients to be applied to heating degree day (HDD) weather parameters to
reflect average use-per-customer. This produces a reliable forecast because of the high
correlation between usage and temperature as depicted in the scatter plot in Figure 2.3.
This figure is intended to show how linear the relationship in usage with increased HDDs
but may look skewed as it considers total load by area instead of a use per customer per
HDD.

Figure 2.3: Example Demand vs. Temperature – 2022

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40,000
60,000
80,000
100,000
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160,000
180,000
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OR Res OR Com OR Ind
WA Res WA Com WA Ind
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HD
D
Demand (MDth)
WA ID
La Grande Klamath Falls
Medford Roseburg
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-5

This forecast considers up to five years of historical city gate data, sorted by service
territory/temperature zone, and then by month. The three-year coefficient most closely
aligns with economic expectations and use within Avista’s territories in the short-term
forecasting in Idaho, Oregon, and Washington. However, Oregon territories include a five-
year demand coefficient based on the OPUC staff’s recommendation 1 discussed in
Chapter 9. Specifically, the Oregon five-year coefficient is lower than expected usage by
over four hundred thousand dekatherms annually from 2023 to 2027. Without this action
item, Avista would have utilized a three-year coefficient across all jurisdictions.

Avista only includes Transportation tariff customer demand for emissions compliance
programs in Oregon and Washington. Avista assumes the average usage based on the
historic baseline in each program. Figure 2.4 is an example of demand for transport
customers from the PLEXOS® model.

Figure 2.4: Monthly Demand of Transport Customers (MMBTU)
The forecast uses coefficients for each degree day plus base usage. The base usage per
customer calculation uses three or five years of July and August data, depending on the
jurisdiction. Average usage in these months divided by the average number of customers
provides the base usage coefficient input into PLEXOS®. This calculation is done for
each area and customer class based on customer billing data demand ratios to reflect
demand without a weather sensitivity.

To derive weather sensitive demand coefficients for each month, Avista removed base
usage from the total and plotted usage by HDD in a scatter plot chart to verify correlation
visually. The process included the application of a linear regression to the data by month
0
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t
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t
h
Tport (OR)Tport (WA)
OR Transport - History WA Transport - History
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-6

to capture the linear relationship of usage to HDD. The slopes of the resulting lines are
the monthly weather sensitive demand coefficients inputs for PLEXOS®. Again, this
calculation is done by area and by customer class using allocations based on customer
billing data demand ratios. Demand by location is illustrated in Figure 2.5.

Figure 2.5: Usage Based on 2-year, 3-year, and 5-year Coefficient

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 drives the resource strategy selection to meet energy and emissions
requirements. The 2023 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. The HDD weather patterns between the Oregon areas are
uncorrelated, while the HDD weather patterns amongst eastern Washington and northern
Idaho portions of the service area are correlated. Thus, Spokane Airport weather data is
used for all Washington and Idaho demand areas.

- 2 4 6 8 10 12 14 16 18 20
2-Year UPC
3-Year UPC
5-Year UPC
2-Year UPC
3-Year UPC
5-Year UPC
2-Year UPC
3-Year UPC
5-Year UPC
2-Year UPC
3-Year UPC
5-Year UPC
2-Year UPC
3-Year UPC
5-Year UPC
2-Year UPC
3-Year UPC
5-Year UPC
Id
a
h
o
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a
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La

G
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g
t
o
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Dekatherms (Millions)
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-7

The NOAA 20-year average weather serves as the base weather forecast to prepare the
annual average demand forecast. The peak day demand forecast includes adjustments
to average weather to reflect a five-day cold weather event. The weather history for the
Avista territories modeled within this IRP uses over 70 years of historical temperatures
and contains minimum, maximum, and average weather data.

Forecasted Temperatures
The temperature forecast uses data developed for the Columbia River Basin by the River
Management Joint Operating Committee (RMJOC)2 comprised of the Bonneville Power
Administration (BPA), United States Army Corps of Engineers, and United States Bureau
of Reclamation. There is significant uncertainty in projecting future temperature. The
RMJOC used an ensemble approach to capture a range of potential outcomes.

Given the sheer volume of data, a method to select a representative set from the 172
modeling combinations was needed. Fortunately, BPA conducted this exercise and
selected a subset of modeling combinations representing a sufficient cross section of
outcomes to calculate generation. The subset represents 19 modeling combinations for
both RCP 4.5 and RCP 8.5.

Representative Concentration Pathways (RCPs) represent different greenhouse gas
(GHG) emission scenarios varying from no future GHG reductions to significant GHG
reductions. The Intergovernmental Panel on Climate Change (IPCC) describes the
scenarios as follows:

• RCP 2.6 – stringent mitigation scenario
• RCP 4.5 & RCP 6.0 – intermediate scenarios
• RCP 8.5 – very high GHG scenarios

RCP 4.5 and RCP 6.0 represent growth in greenhouse gas emissions, but the growth is
lower in comparison to RCP8.5 due to mitigation strategies. In the time horizon of the IRP
the increase in global mean surface temperature for RCP4.5 and RCP6.5 are 1.4 and 1.3
degrees Celsius, respectively, and therefore have a similar impact on the IRP analysis.

Table 2.3 provides a comparison of the temperature increases projected under the
various scenarios.

2 Climate and Hydrology Datasets for RMJOC Long-Term Planning Studies: Second
Edition (RMJOC-II)
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-8

Table 2.3: Comparison of Temperature Increases by Representative Concentration
Pathway

Scenario
2046-
2065 2081-2100
Mean Likely range Mean Likely range
Global Mean
Surface
Temperature
Change (°C)
RCP 2.6 1.0 0.4 to 1.6 1.0 0.3 to 1.7
RCP 4.5 1.4 0.9 to 2.0 1.8 1.1 to 2.6
RCP 6.0 1.3 0.8 to 1.8 2.2 1.4 to 3.1
RCP 8.5 2.0 1.4 to 2.6 3.7 2.6 to 4.8

The results of the RCP 4.5 and RCP 6.0 scenarios are similar during the 2023 IRP
planning horizon. Given the RCP 8.5 is at the high end of potential future GHG emissions
where there are significant worldwide efforts to mitigate GHG emissions removes this
future as a realistic option. The lower RCP 2.6 was not chosen due to the extreme levels
of emission reductions which did not seem probable, therefore the intermediate scenarios
with similar results during the 2023 IRP planning horizon were the focus. Avista selected
the RCP 4.5 modeling for use in this IRP.

Warming temperatures will impact average demand yet maintain a peak risk and require
flexible resources to meet these extreme temperatures in each planning area.
Specifically, there will be less heating required in the winter.

HDDs are inputs to the PLEXOS® model. A 20-year moving average of the HDDs is used.
The 2021 IRP the baseline forecast used the average of the most recent 20 years as a
static input for all forward forecast years. In this analysis, the median daily average
temperature of the RCP 4.5 model is used as the temperature data set compared to the
20-year moving average for each forecast year. Figure 2.6 presents the net change in
load resulting from using the RCP 4.5 data in the forecast model compared to using the
most recent 20-year average held constant over all future years. The net change is
presented in Figure 2.6. The demand decreases as warming temperatures are
incorporated into the 20-year moving average.

Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-9

Figure 2.6: Impact of RCP 4.5 Temperature Data on Load Forecast

Peak Day Design Temperature
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. In prior IRP’s
a coldest on record approach was considered the planning standard. This IRP uses a
different approach, first the coldest average daily temperature for each year is calculated
for the past thirty years, by planning area. For future years, the 99th percentile of the cold
weather daily temperature from the RCP 4.5 model is used to reflect probable cold days.
Then the forecasted peak day uses a rolling 30 years of data and including both historic
temperature and forecasted peak day temperatures. As shown in Figure 2.7. the volatile
nature of the 99th percentile as calculated for each year with the prior 30 years of data
creates volatility in future planning temperatures. For example, the 2024 the calculated
peak temperature for Spokane is -12 degrees Fahrenheit but drops to -14 degrees
Fahrenheit in 2027. To smooth out the whipsaw effect of these values, and subsequent
overbuilding or underbuilding of the required resources, a smoothing calculation was used
which utilizes the coldest on record temperature and the peak temperature calculation in
2045 and connects the two linearly.

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(
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Historic Temperatures + Peak Historic and Forecasted + Peak
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-10

Figure 2.7: Spokane Weather Station – Weather Planning Standard Comparison

The new 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 28th each year to
safeguard the availability of resources to serve customers in late season cold weather
events. With supply side resources in the Pacific Northwest growing further constrained,
managing supply along with the ability to serve cold days is paramount. For the
southwestern Oregon service territories (Medford, Roseburg, and Klamath Falls), the
model assumes this event on and around December 20th each year. The following section
provides a comparison of prior IRP planning standard versus the updated methodology
(Table 2.4).

-30
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(
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-
F)
Min of GEG Avg.99%Coldest on Record Trend Line Peak
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-11

Table 2.4: Peak Day Design Temperature

Area Coldest on Record
(Prior IRP’s)
99% Probability Avg.
Temp (by 2045)
La Grande -10 -8.0
Klamath Falls -7 -5.1
Medford 4 11.7
Roseburg 10 11.7
Spokane -17 -14.6

When considering changing weather in our service territories, a historic comparison is
helpful. This Z-statistic analysis is used to compare the deviation from an average
temperature over each stated timeframe. Distributions of these daily deltas as compared
to the average daily weather over the timeframe will emerge. The Spokane weather area
maintains the same shape from reference period where a coldest on record set of
temperatures occurred. A slight deviation to the positive side of the Z-statistic points to a
general warming trend as compared to the reference period. Movement towards the right
on the X axis points to an increased deviation as compared to the reference period
indicating a shift to warmer weather. The following figures illustrate a period of 30-year
weather compared to recent weather by planning region for December, January, and
February.

Figure 2.8: Spokane Historical Temperature Distribution

0%
5%
10%
15%
20%
25%
30%
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Fr
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Z-statistic
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-12

Figure 2.9: Medford Historical Temperatures

Figure 2.10: La Grande Historical Temperatures

0%
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25%
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0%
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Z-statistic
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-13

Figure 2.11: Klamath Falls Historical Temperatures

Figure 2.12: Roseburg Historical Temperatures

0%
5%
10%
15%
20%
25%
-5
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Fr
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Z-statistic
1951/52-1980/81 Reference Period 2001/02 - 2020/2021 Period
0%
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Fr
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Z-statistic
1951/52-1980/81 Reference Period 2001/02 - 2020/21 Period
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-14

Weather
In order to evaluate weather and its effect on the portfolio, Avista developed 500
simulations (draws) using PLEXOS®’s stochastic capabilities. 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 2.5) are distributed on a daily basis for a month in history
with similar HDD totals. The resulting draws provide a weather pattern with variability in
the total HDD values, as well as variability in the shape of the weather pattern. This
provides a more robust basis for stress testing the deterministic analysis.

Table 2.5: Example of Monte Carlo Weather Inputs – Spokane

The model considers five weather areas: Spokane, Medford, Roseburg, Klamath Falls
and La Grande. A new weather planning standard was introduced in the 2021 IRP, and
Avista assessed the frequency of when the weather planning standard peak day occurs
in each area from the simulation data. The stochastic analysis shows that in over 500,
20-year simulations, a peak day (or more) occurs with enough frequency to utilize the
new planning standard for this IRP. This topic remains a subject of continued analysis.

See Figure 2.13 through Figure 2.17 for the number of peak day occurrences by weather
area. To help explain the number of peak day occurrences, Avista looks to the process
itself. Monte Carlo simulations use historic data to obtain randomly generated weather
events. Due to the change in planning standard, no peak days were simulated above the
historic coldest on record temperature. Though due to the number of peak days occurring
in the past 30 years, probability sees it is a higher likelihood of occurrence.

Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-15

Figure 2.13: Frequency of Peak Day Occurrences – Spokane

Figure 2.14: Frequency of Peak Day Occurrences – Medford

0
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Max Average Annual Count of Peak - 79.6+ HDD
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Max Average Annual Count of Peak - 53.3+ HDD
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-16

Figure 2.15: Frequency of Peak Day Occurrences – Roseburg

Figure 2.16: Frequency of Peak Day Occurrences – Klamath Falls

0
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Max Average Annual Count of Peak - 53.3+ HDD
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Max Average Annual Count of Peak - 70.1+ HDD
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-17

Figure 2.17: Frequency of near Peak Day Occurrences – La Grande

Load Forecast
The combination of the elements discussed in this chapter produce an estimated energy
need as illustrated in Table 2.6: Load Forecast. The forecast is broken out by jurisdiction,
separated by firm and transport only expectations.

0
100
200
300
400
500
600
0
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20
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Max Average Annual Count of Peak - 70.1+ HDD
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-18

Table 2.6: Load Forecast (Thousand Dekatherms)

Year Washington Idaho Oregon Washington
Transport
Oregon
Transport
Total Total w/
Transport
2023 19,436 10,441 9,597 2,479 4,441 39,475 46,394
2024 19,604 10,644 9,759 2,451 4,425 40,007 46,884
2025 19,549 10,724 9,845 2,448 4,424 40,118 46,990
2026 19,620 10,855 9,968 2,448 4,424 40,443 47,315
2027 19,657 10,956 10,069 2,448 4,423 40,682 47,553
2028 19,816 11,118 10,202 2,443 4,421 41,136 48,000
2029 19,675 11,128 10,237 2,435 4,420 41,040 47,895
2030 19,652 11,192 10,316 2,430 4,419 41,159 48,008
2031 19,726 11,295 10,429 2,426 4,418 41,451 48,295
2032 19,821 11,422 10,544 2,424 4,418 41,786 48,628
2033 19,790 11,475 10,604 2,425 4,419 41,869 48,713
2034 19,785 11,549 10,672 2,427 4,420 42,006 48,854
2035 19,864 11,665 10,819 2,432 4,422 42,348 49,203
2036 20,122 11,867 11,014 2,434 4,423 43,003 49,860
2037 20,130 11,947 11,109 2,440 4,425 43,186 50,051
2038 20,082 12,005 11,201 2,450 4,427 43,289 50,167
2039 20,128 12,106 11,300 2,461 4,430 43,533 50,424
2040 20,209 12,216 11,436 2,466 4,431 43,861 50,758
2041 20,173 12,270 11,507 2,473 4,432 43,950 50,855
2042 20,193 12,356 11,607 2,474 4,433 44,155 51,062
2043 20,210 12,440 11,732 2,510 4,457 44,382 51,348
2044 20,424 12,624 11,864 2,510 4,457 44,912 51,879
2045 20,398 12,698 11,885 2,510 4,457 44,981 51,948

The peak load demand forecast is included in Table 2.7. 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.

Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-19

Table 2.7: Peak Day Load Forecast (Thousand Dekatherms)

Year Washington Idaho Oregon Washington
Transport
Oregon
Transport
Total Total w/
Transport
2023 219.89 111.89 90.11 8.57 14.24 378.37 400.62
2024 221.98 113.86 90.96 8.35 14.20 382.50 403.86
2025 224.00 115.68 91.76 8.48 14.19 387.11 409.22
2026 226.17 117.40 92.59 8.49 14.19 391.42 413.54
2027 228.09 118.91 93.25 8.48 14.19 395.42 417.53
2028 230.01 120.40 94.03 8.33 14.18 398.71 420.03
2029 231.84 121.83 94.62 8.45 14.18 402.47 424.54
2030 233.77 123.22 95.36 8.44 14.18 406.13 428.18
2031 235.75 124.63 95.94 8.42 14.18 410.08 432.12
2032 237.77 126.10 96.58 8.28 14.18 413.76 435.02
2033 239.76 127.55 97.24 8.42 14.18 417.06 439.10
2034 241.80 129.02 97.91 8.43 14.18 421.29 443.33
2035 243.83 130.49 98.65 8.44 14.19 425.34 447.40
2036 245.85 131.97 99.23 8.31 14.19 429.59 450.89
2037 247.83 133.42 99.89 8.46 14.19 433.40 455.49
2038 249.84 134.87 100.46 8.49 14.20 436.76 458.89
2039 251.80 136.32 101.13 8.52 14.21 439.47 461.64
2040 253.75 137.75 101.86 8.39 14.21 442.56 463.98
2041 255.68 139.15 102.55 8.55 14.21 446.40 468.61
2042 257.58 140.55 103.14 8.56 14.22 450.20 472.41
2043 259.53 141.99 104.08 8.65 14.28 454.17 476.55
2044 261.44 143.42 104.65 8.51 14.28 457.25 478.85
2045 263.32 144.92 105.23 8.65 14.28 460.21 482.59

Measuring risk in weather is done through a statistical approach of analyzing each of
these measures to reflect the uncertain nature of a future outcome. Risk can be measured
by the variation of cost outcome of resources in addition to unknown weather events and
the ability to serve customer demand. This analytical perspective provides confidence in
the conclusions and stress tests the robustness of the selected portfolio of resources,
thereby mitigating analytical risks. The system demand for these 500 futures from 2023
to 2045 is illustrated in Figure 2.18 with demand by jurisdiction in Figures 2.19 to 2.21.

Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-20

Figure 2.18: System Demand – 1,000 Dth (500 Draws)

Figure 2.19: Idaho Demand – 1,000 Dth (500 Draws)

Average 49,533
Min 42,822
Max 59,148
Median 49,448
5th %45,902
95th %53,556
Std. Dev.2,332
Average 11,710
Min 9,291
Max 15,081
Median 11,696
5th %10,349
95th %13,153
Std. Dev.858
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-21

Figure 2.20: Oregon Demand – 1,000 Dth (500 Draws)

Figure 2.21: Washington Demand – 1,000 Dth (500 Draws)

Average 15,259
Min 13,565
Max 17,288
Median 15,219
5th %14,123
95th %16,461
Std. Dev.745
Average 22,564
Min 19,666
Max 27,726
Median 22,492
5th %20,933
95th %24,468
Std. Dev.1,082
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-22

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 2.7
identifies the scenarios developed for this IRP. The Average Case represents the case
used for normal planning purposes, such as corporate budgeting, procurement planning,
PGAs, and General Rate Cases. The Preferred Resource Case reflects the 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 given the volatile nature
of key assumptions, including weather and price.

Table 2.8: Demand Scenarios

Preferred Resource Case – Our expected case
based on assumptions and costs with a least risk
and least cost resource selection
High Customer Case – A high demand
case to measure risk of additional customer
and meeting our emissions and energy
obligations
Electrification Expected Conversion Costs –
Expected conversion costs case to show the risk
involved with energy delivered through the natural
gas infrastructure moving to the electric system
Average Case – Non climate change
projected 20-year history of average daily
weather and excludes peak day
Hybrid Case – Natural Gas used for space heat
below 40⁰ F while transferring all other usage to
electricity.

During 2023, the Average Case demand forecast indicates Avista will serve an average
of 379,669 core natural gas customers with 38,871,519 Dth of natural gas. By 2042,
Avista projects 469,703 core natural gas customers with an annual energy demand of
45,082,213 Dth. In Washington/Idaho, the projected number of customers increases at
an average annual rate of 1.22%, with demand growing at a compounded average annual
rate of 0.78%. In Oregon, the projected number of customers increases at an average
annual rate of 0.89%, with demand growing 0.80% per year.

The Expected Case demand forecast indicates Avista will serve an average of 379,669
core natural gas customers with 39,518,082 Dth of natural gas in 2023. By 2042, Avista
projects 469,703 core natural gas customers with an annual demand of 44,199,537 Dth.

Table 2.8 shows system forecasted demand for the demand scenarios on an average
daily basis for each year.3

3 Appendix 2.1 shows gross demand, conservation savings and net demand.
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-23

Table 2.9: Annual Demand – 2023 IRP Scenarios (000 dth)

Scenario 2025 2035 2045
Hybrid Case 46,702 45,155 44,772
Average Case 46,406 49,612 53,042
Electrification - Expected Conversion Costs
46,270 41,447 38,368 Electrification - High Conversion Costs
Electrification - Low Conversion Costs
PRS - High Prices 46,933 49,122 51,909
PRS
46,990 49,203 51,948
PRS - Allowance Price Ceiling
Limited RNG Availability
Carbon Intensity
Social Cost of Carbon
Interrupted Supply
PRS - Low Prices 47,011 49,217 51,950
High Customer Case 47,456 50,913 55,089

The IRP balances forecasted demand with existing and new supply alternatives. Since
new supply sources include conservation resources, which reduce demand reduction, the
demand forecasts prepared and described in this section include existing energy
efficiency standards and normal market acceptance levels. The methodology for
modeling energy efficiency initiatives is in Chapter 3.

Alternative Forecasting Methodologies
There are many forecasting methods available and used throughout different industries.
Avista uses methods to enhance forecast accuracy, facilitate meaningful variance
analysis, and allows for modeling flexibility to incorporate different assumptions. Avista
believes the IRP statistical methodology to be sound and provides a robust range of
demand considerations while allowing for the analysis of different statistical inputs by
considering both qualitative and quantitative factors unless there are fundamental
changes to the industry. These factors come from data, surveys of market information,
fundamental forecasts, and industry experts. Avista is always open to new methods of
forecasting natural gas demand and will continue to assess alternative methodologies for
possible inclusion in the dynamic demand forecasting methodology.

Key Issues
Demand forecasting is a critical component of the IRP requiring careful evaluation of the
current methodology and use of scenario planning to understand how changes to the
underlying assumptions will affect the results. The evolution of demand forecasting over
recent years has been dramatic, causing a heightened focus on variance analysis and
trend monitoring. Current techniques have provided sound forecasts with appropriate
variance capabilities. However, Avista is mindful of the importance of the assumptions
driving current forecasts and understands there will be change over time. Therefore,
Chapter 2: Demand Forecasts
Avista Corp 2023 Natural Gas IRP 2-24

monitoring key assumptions driving the demand forecast is an ongoing effort and will be
shared with the TAC as they develop. Avista intends to explore the use of an end-use
model to help forecast demand in future IRPs.4

4 Action # 9 in Chapter 9 - Action Plan
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-1

3. Demand Side Resources

Avista is committed to offering natural gas energy efficiency (EE) programs to residential,
low income, commercial and industrial customer segments when it is feasible to do so in
a cost-effective manner as prescribed within each jurisdiction. Avista began offering
natural gas 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 savings 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 future years.

Avoided Cost
The preliminary cost-effective energy efficiency potential is determined by applying the
stream of annual natural gas avoided costs to the Avista-specific supply curve for EE
resources. These costs include commodity costs, distribution cost adders, storage costs,
social cost of greenhouse gas at 2.5%, fuel costs to move the gas from point A to point
B, and a 10% preference adder for EE among others discussed in Chapters 4 & 5. A
quantity of EE acquisition is provided by Applied Energy Group (AEG) for Idaho and
Washington and while the Energy Trust of Oregon (ETO) handles the analysis and
program delivery for Oregon. The estimated results are then decremented from Avista’s
load forecast. As the model changes based on updated assumptions and costs, updated
avoided costs are considered by AEG and ETO to estimate total potential in the CPA.
The resulting avoided costs were provided to AEG to use in selecting cost-effective EE
potential within Avista’s service territories.

The avoided-cost figures represent the unit cost to serve the next unit of demand with a
supply-side resource option during a given period. If an energy efficiency measure’s total
resource cost (Oregon and Washington), or utility cost (Idaho), is less than this avoided
cost, it will be cost effective to reduce customer demand and Avista can avoid commodity,
storage, transportation, and other supply resource costs while reducing the risk of
unserved demand in peak weather.

PLEXOS® calculates marginal cost data by day, month, and year for each demand area.
A summary graphical depiction of avoided annual and winter costs for each jurisdictional
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-2

area is in Figure 3.1 and 3.2. The detailed data is in Appendix 6.4. Appendix 3.2 describes
this concept more fully and includes specific requirements required in modeling for the
Oregon service territory.

Figure 3.1: Annual Avoided Cost (by jurisdiction)

Figure 3.2: Winter Avoided Cost (by jurisdiction)

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Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-3

Idaho and Washington Conservation Potential Assessment
As part of its process for identifying its Conservation Potential Assessment (CPA), also
known as an EE potential assessment, Avista issued an RFP to identify qualified third
parties to estimate potential EE savings opportunities. Avista chose Applied Energy
Group (AEG) to perform an independent CPA for Washington and Idaho natural gas. The
CPA is Avista’s tool to identify the level of energy efficiency it anticipates achieving over
a 20-year period. Moreover, the CPA is used to identify the conservation target for each
jurisdiction that it operates in.

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 of 2023 to 2042. To produce a reliable and
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 in
absence of 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 2023 to 2045
planning horizon.
• Deliver a fully configured end-use conservation planning model, LoadMAP, for
Avista to use in future potential and resource planning initiatives.
• 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 to 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
lead to a specific standardized cost-effectiveness test. The section below outlines and
describes the various perspectives.

Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-4

Total Resource Cost Test
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, administrative costs, and the
incremental costs between standard and high efficiency equipment.

Utility Cost Test
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. The UCT is also known as the program administrator cost
test (PAC). As part of the CPA, each cost test is applied to the jurisdictions according to
the jurisdictions primary cost test methodology. Idaho and Washington have traditionally
use the UCT while Oregon has used a modified TRC Test.

Washington’s EE program evaluation will transition away from the UCT to the TRC
method as its primary cost effectiveness test. As a condition to Avista’s 2022-23 Natural
Gas Biennial Conservation Plan1, Avista agreed to conduct a TRC analysis assesses all
costs and all benefits of EE measures. Also included in the conditions is the requirement
to include the costs of greenhouse gas emissions per RCW 80.28.380. Since the UCT
does not include these in their calculation, the requirement necessitates a change in the
primary cost-effectiveness test. Therefore, for this CPA, Avista requested that AEG
prepare the Washington level of EE on the TRC basis. Table 3.1 summarizes the cost
tests used by each jurisdiction.

Table 3.1: Cost Effectiveness Test

State Total
Resource Cost
Utility Cost
Test
Idaho X
Oregon X
Washington X

Washington and Idaho Energy Efficiency Potential
First-year TRC achievable economic potential in Washington is 111,992 dekatherms. This
increases to a cumulative total of 225,734 dekatherms in the second year and 2,497,540
dekatherms by 2045. Table 3.2 summarizes the results for Avista’s Washington service
territory at a high level. AEG analyzed the EE potential for the residential, commercial,
and industrial market sectors.

1 UG-210827 Order No. 01, Attachment A.
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-5

Table 3.2: Washington Energy Efficiency Potential by Case (dekatherms)2

Scenario 2023 2024 2025 2035 2045
Baseline Forecast (Dth) 19,632,329 19,782,233 19,934,947 21,966,934 24,576,214
Cumulative Savings (Dth)
TRC Economic
Potential 111,992 225,734 361,485 1,833,863 2,497,540
Achievable Technical
Potential 191,654 423,238 686,518 3,774,115 4,938,238
Technical Potential 429,564 884,194 1,375,956 6,455,295 8,637,218
Energy Savings (% of Baseline)
TRC Economic
Potential 0.6% 1.1% 1.8% 8.3% 10.2%
Achievable Technical
Potential 1.0% 2.1% 3.4% 17.2% 20.1%
Technical Potential 2.2% 4.5% 6.9% 29.4% 35.1%

Table 3.3 summarizes the results for Avista’s Idaho service territory at a high level. First-
year UCT achievable economic potential in Idaho is 46,414 dekatherms. This increases
to a cumulative total of 96,705 dekatherms in the second year and 1,278,511 dekatherms
by 2045.

Table 3.3: Idaho Energy Efficiency Potential by Case (dekatherms)

Scenario 2023 2024 2025 2035 2045
Baseline Forecast (Dth) 9,781,790 9,893,452 10,003,402 11,501,243 13,451,001
Cumulative Savings (Dth)
UCT Economic Potential 46,414 96,705 155,748 906,240 1,278,511
Achievable Technical
Potential 105,612 228,853 371,295 2,144,539 2,885,725
Technical Potential 254,213 498,497 772,091 3,673,174 5,060,646
Energy Savings (% of Baseline)
UCT Economic Potential 0.5% 1.0% 1.6% 7.9% 9.5%
Achievable Technical
Potential 1.1% 2.3% 3.7% 18.6% 21.5%
Technical Potential 2.6% 5.0% 7.7% 31.9% 37.6%

2 See Appendix Chapter 3
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-6

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 2023 in its analysis, the cycle for establishing annual EE targets begins in 2024
and runs through 2025 as a biennial period. Therefore, for the purpose of target setting,
cumulative values are used with the first year of the study, 2023, removed. An additional
CPA for Avista’s Washington transport customer group was conducted. The entire CPA
report including the methodology can be found in Appendix 3.

Table 3.4 and 3.5 summarizes the 2024 and 2025 targets for Washington and Idaho
respectively as a result of the CPA. As stated above the 2023 estimates were removed
from the overall cumulative value to arrive at the 2024 and 2025 incremental targets.

Table 3.4: Washington 2024-2025 Conservation Target by Sector, (therms)

Customer
Segment 2024 2025 Total
Low Income 119,407 160,534 279,941
Residential 368,556 498,644 867,199
Commercial 627,625 676,226 1,303,851
Industrial 19,874 20,193 40,067
Total 1,135,461 1,355,596 2,491,058

Table 3.5: Idaho 2024-2025 Conservation Target by Sector, (therms)

Customer Segment 2024 2025 Total
Low Income 25,176 31,788 56,964
Residential 256,634 319,784 576,418
Commercial 204,566 222,235 426,802
Industrial 15,422 15,530 30,952
Total 501,799 589,337 1,091,136

Avista made one adjustment to the CPA impacting its overall EE target. The measure
“Gas Furnace – Maintenance” was included in the study provided by AEG and was also
included in the economic screen to inform the overall targets for each state. While other
measures included in the study focus on efficiency, controls, commissioning or
weatherization, the maintenance measure is intended to return existing equipment to its
“nameplate” or as-designed efficiency level. The feasibility of reaching the level of
potential outlined in the study is unlikely since there are no available sources for a deemed
savings value for this measure that can be vetted and relied upon. In addition, the
evaluation of a maintenance-type program creates difficulty since individual unit service
needs vary substantially from project to project, and in many cases, may not result in
efficiency gains. Since savings values within the potential do not have an adequate level
of certainty, the maintenance measure has been removed from the economic potential.
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-7

The impact of this adjustment is a reduction of 386,757 therms for Washington over the
two-year period and 220,820 therms for Idaho over the two-year period.

Oregon Energy Efficiency Targets
As technologies and EE policies evolve over the IRP timeline the Company works with
the Oregon Public Utility Commission, Community Action Agencies, Energy Trust of
Oregon, and other stakeholders to adjust offerings to maximize EE savings. AEG
conducted a CPA for Avista’s Oregon low-income, interruptible and transport customer
groups to enable the Company to better understand potential when designing programs
for these customers. Energy Trust of Oregon (ETO) conducted a CPA for Avista’s
residential, small, and large commercial customer groups which they have served with
energy efficiency programs since 2017. The entire CPA report including the methodology
can be found in Appendix 3.

The Company has exclusively worked with Community Action Agencies (CCAs) to
implement the Avista Oregon Low Income Energy Efficiency (AOLIEE) Program. Agency
primarily install shell measures, air and duct sealing for our low-income customers. The
results of identified top EE measures were discussed with the CCAs and ETO to
determine the measures that are readily deployable in the near term, but no measures
have been removed from the overall potential. Throughout 2022, Avista engaged the
CCAs that administer the AOLIEE Program, as well as several other organizations to
serve its low-income households,3 via meetings, email correspondence, and telephone
conversations to gain community perspective and collaboratively discuss new ways to
possibly increase customer participation in the Program. As noted in the Company’s 2021
AOLIEE Report, Avista also partnered with a third-party contractor, Empower Dataworks,4
to complete an Energy Burden Assessment (Assessment) in 2022.5 This Assessment
informs the Company of existing gaps in Program structure and provides data needed to
better target Avista’s energy burdened customers needing weatherization services.

These engagements provide the basis for the Company’s requested modifications to its
AOLIEE Program for 2023, which were approved by the Commission in Docket No. ADV
1452/Advice No. 22-11-G. These modifications for the 2023 Program year, are intended
to expand the reach of the existing Program and to prioritize energy burdened customers
within these communities to ensure energy efficiency services available are reaching
those that need them most. Avista will continue to work with interested parties including
Energy Trust of Oregon to ramp up EE programs to reduce the energy burden for low-
income customers. Table 3.6 summarizes the potential results for low-income customers.

3 Such organizations include Federally Recognized Tribes and Saint Vincent de Paul.
4 Empower Dataworks, a third-party consultant specializing in data, informed marketing, and engineering
analytical services, was hired by the Company in 2021 to perform an Energy Burden Assessment. See
https://empowerdataworks.com/ for more detail regarding Empower Dataworks.
5https://apps.puc.state.or.us/edockets/edocs.asp?FileType=HAH&FileName=um2211hah135626.pdf&Doc
ketID=23122&numSequence=66
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-8

Table 3.6: Summary of Oregon Low-Income Energy Efficiency Potential

2023 2024 2025 2035 2045
Baseline Projection (Dth)[1] 914,784 919,566 924,873 999,238 1,128,049
Cumulative Savings (Dth)
Achievable Economic Potential 3,816 7,383 12,114 60,487 99,838
Achievable Technical Potential 8,877 18,471 30,274 165,088 205,045
Technical Potential 14,319 28,147 44,987 226,689 295,472
Cumulative Savings (% of
Baseline)

Achievable Economic Potential 0.4% 0.8% 1.3% 6.1% 8.9%
Achievable Technical Potential 1.0% 2.0% 3.3% 16.5% 18.2%
Technical Potential 1.6% 3.1% 4.9% 22.7% 26.2%

Avista has not offered carbon reduction programs via EE for transport and interruptible
customers in previous years. The results of top efficiency measures were shared and
discussed with ETO; Through these discussions, the ETO will offer EE programs to
interruptible customers starting in March of 2023. Measures such as shell measures,
equipment upgrades, strategic energy management, and custom projects6 are available.
The Company will continue to work with interested parties to determine appropriate EE
programs for transport customers with an estimated start date mid-2023. Interruptible and
transport customers’ energy savings potential is shown in Table 3.7, 3.8, and 3.9 below.

Table 3.7: Summary of Oregon Interruptible Industrial Energy Efficiency Potential

Summary of Energy Savings
(Dth), Selected Years
2023 2024 2027 2032 2042
Reference Baseline (Dth) 1,509,283 1,507,701 1,503,695 1,499,146 1,494,147
Cumulative Savings (Dth)
Achievable Economic 7,690 20,982 63,008 141,741 252,992
Achievable Technical 8,252 22,265 66,441 148,323 262,025
Technical Potential 12,571 31,598 89,499 189,969 322,829
Energy Savings (% of Baseline)
Achievable Economic 0.5% 1.4% 4.2% 9.5% 16.9%
Achievable Technical 0.5% 1.5% 4.4% 9.9% 17.5%
Technical Potential 0.8% 2.1% 6.0% 12.7% 21.6%

6 https://www.energytrust.org/industry-agriculture/
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Avista Corp 2023 Natural Gas IRP 3-9

Table 3.8: Summary of Oregon Interruptible Commercial Energy Efficiency
Potential

Summary of Energy Savings
(Dth), Selected Years
2023 2024 2027 2032 2042
Reference Baseline (Dth) 389,600 386,846 380,130 373,268 367,372
Cumulative Savings (Dth)
Achievable Economic 904 2,441 8,398 23,243 47,598
Achievable Technical 1,336 3,499 11,632 30,283 58,455
Technical Potential 5,998 12,666 32,618 66,549 103,852
Energy Savings (% of Baseline)
Achievable Economic 0.2% 0.6% 2.2% 6.2% 13.0%
Achievable Technical 0.3% 0.9% 3.1% 8.1% 15.9%
Technical Potential 1.5% 3.3% 8.6% 17.8% 28.3%

Table 3.9: Summary of Oregon Transport Industrial Energy Efficiency Potential

Summary of Energy Savings
(Dth), Selected Years
2023 2024 2027 2032 2042
Reference Baseline (Dth) 2,782,962 2,782,624 2,781,477 2,779,303 2,775,037
Cumulative Savings (Dth)
Achievable Economic 9,534 28,080 84,925 184,338 361,139
Achievable Technical 9,531 28,086 84,876 183,737 359,563
Technical Potential 12,498 35,485 105,602 225,654 436,548
Energy Savings (% of Baseline)
Achievable Economic 0.3% 1.0% 3.1% 6.6% 13.0%
Achievable Technical 0.3% 1.0% 3.1% 6.6% 13.0%
Technical Potential 0.4% 1.3% 3.8% 8.1% 15.7%

As implementor of EE programs for the Company’s residential, small, and large
commercial customers. ETO provides a full suite of energy efficiency measures7 .
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 Plan8. Table 3.10 below shows potential results over a 20-
year horizon.

7 https://www.energytrust.org/
8 https://www.energytrust.org/about/reports-financials/budget-action-plan/
Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-10

Table 3.10: 20-Year Cumulative Savings Potential by Type (Millions of Therms)
Technical
Potential
Achievable
Potential
Cost-
Effective
Achievable
Potential
Energy Trust
Deployed Savings
Projection
Residential 20.3 16.2 15.9 9.9
Commercial 6.9 5.8 5.5 3.8
Industrial 0.4 0.3 0.3 0.3
Exogenous9 - - - 1.4
Total 27.6 22.3 21.6 15.3

Additionally, in 2023 Avista will meet with ETO, and other utilities to explore a hybrid
heating pilot with planning beginning during the second quarter. The company will also
explore during 2023 whether to implement in 2024 a targeted EE distribution project in
the natural gas system which is discussed further in Chapter 8 of the IRP.

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.

While Avista has historical electric DR experience, NGDR programs have not been
reviewed prior to this IRP. Avista retained AEG to perform the first NGDR potential
assessment study for Avista’s Oregon, Washington, and Idaho service territories.

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 23-year planning
horizon (2023-2045). These estimates are then modeled in the IRP to determine the value
and cost effectiveness of each program on Avista’s system.

Figure 3.1 outlines AEG’s approach to determine potential DR programs in Avista’s
service territories. All NGDR pricing programs and behavioral programs included in this
study require Advanced Metering Infrastructure (AMI) as an enabling technology.
Currently Washington is the only state in Avista’s service territory with AMI.

9 The final deployed savings projection includes savings calculated outside of the modeling process
consisting of the large project adder and unclaimed market savings.
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Avista Corp 2023 Natural Gas IRP 3-11

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 provided 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 3.3: Program Characterization Process

This process identified the five NGDR program options shown in Table 3.11. The different
types of NGDR programs include two broad classifications: curtailable/controllable NGDR
and rate design programs. Except for the behavioral program, curtailable/controllable
NGDR programs represent firm, dispatchable and reliable resources to meet peak-period
loads. Rate design options offer non-firm load reductions that might not be available when
needed but create a reliable pattern of potential load reduction. Pricing options include
time-of-use and variable peak pricing. Each option requires a new rate tariff for each state
in Avista’s service territories.

Table 3.11: NGDR Program Options by Market Segment

DR Program Participating Market Segment
Program
Type
Program
Option
Residential Commercial Industrial
Curtailable
Controllable
DR
DLC Smart Thermostat X X
Third Party Contracts X X
Behavioral* X X
Rates Time-of-Use Opt-in* X X X
Variable Peak Pricing Rates* X X X

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
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Avista Corp 2023 Natural Gas IRP 3-12

five years to ramp up to maximum participation levels. Customer participation rate
assumptions along with program costs and potential are detailed in Tables 3.9 and 3.10.

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 3.9 and 3.10.

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 behavioral reporting
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 3.9 and 3.10.

Time of Use Rates (Opt-In)
A Time of Use (TOU) rate is a time-varying rate. Relative to a revenue-equivalent flat rate,
the rate during on-peak hours is higher, while the rate during off-peak hours is lower. This
provides customers with an incentive to shed or shift consumption out of the higher-price
on-peak hours to the lower cost off-peak hours. TOU is not an NGDR option, per se, but
rather a permanent load shedding or shifting opportunity. Large price differentials are
generally more effective than smaller differentials for TOU programs. This study assumes
an opt-in rate, where participants voluntarily enroll in the rate program. Customer
participation rate assumptions along with program costs and potential are detailed in
Tables 3.9 and 3.10.

Variable Peak Pricing
The Variable Peak Pricing (VPP) amount changes daily to reflect system conditions and
costs for peak hours. Under a variable peak pricing program, on-peak prices for each
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Avista Corp 2023 Natural Gas IRP 3-13

weekday are made available the previous day. Through a VPP program customers are
billed for their actual consumption during the billing cycle at these prices. Over time,
establishment of event-trigger criteria enables customers to anticipate events based on
extreme weather or other factors. System contingencies and emergency needs are good
candidates for VPP events. VPP program participants are required to be enrolled in a
TOU rate option. Customer participation rate assumptions along with program costs and
potential are detailed in Tables 3.9 and 3.10.

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 “best-practice”
estimates for program participation.

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 3.12 shows the steady-state participation rate assumptions for each NGDR
program option. Eligible customers for each customer class are calculated based on
market characterization and equipment end use saturation. The values shown are
considered maximum participation rates with a ramp rate of 5 years. AEG used derated
electric participation rates for natural gas DR programs rather than a direct comparison
to the pilot programs described above.

Table 3.12: NGDR Program Steady-State Participation Rates
(Percentage of Eligible Customers)

DR Program Residential Commercial Industrial
Smart Thermostats DLC Heating 9% 9% -
Third Party Contracts - 5% 13%
Behavioral* 12% 12% -
Time-of-Use* 8% 8% 8%
Variable Peak Pricing* 15% 15% 15%
*Requires AMI and only available in WA State

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 for each program
independently and on a standalone basis.

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Avista Corp 2023 Natural Gas IRP 3-14

If Avista offers more than one program, the potential for double counting exists. To
address this possibility, a participation hierarchy was assumed and defines the order
customers take the programs for an integrated approach. These savings and costs results
were then used in Avista’s modeling. Additional detail on NGDR resource assumptions
can be found in AEG’s Natural Gas CPA report, Appendix 3.

The estimated savings for reach program and its levelized costs are shown in Table 3.13.
The cost of the programs within these tables represents the on-going operations and
capital cost required to start and maintain these programs. The capital costs are
amortized and recovered over a 10-year period. These tables include the estimated
potential dekatherm savings for 2030 and 2045 for illustrative purposes of program
potential. These estimates are the expected amount of demand reduction and net savings
from all program participants.

Table 3.13: System Program Cost and Potential

Program Costs $/Dth
year
Winter (Dth) Potential
2030 2045
Smart Thermostats DLC Heating $5,756 3,336.53 4,000.84
Third Party Contracts $135,937 25.38 29.71
Behavioral* $11,849 304.66 364.53
Time-of-Use* $18,883 232.21 280.69
Variable Peak Pricing* $4,474 1,192.69 1,440.26
Total Potential 5,091.47 6,116.02

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 does not include
fuel switching in the demand forecast, but rather includes specific fuel use electrification
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 toward the
product being produced. Avista does not have many industrial customers in its territories,
with the overall system use of industrial customer around one percent 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
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Avista Corp 2023 Natural Gas IRP 3-15

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 concern is 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. This will be further discussed in
Chapter 7.

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 is 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. Efficiency estimates are illustrated in Figure 3.4 and indicate
expected electric space heating efficiency is higher than natural gas space heat
efficiency. Implications of these efficiencies will come into focus when paired with weather
regions, expected energy costs, and conversion costs.

Figure 3.4: Space Heat Efficiency by Degrees Fahrenheit and Fuel

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Space Heat Efficiency - Electricity
Space Heat Efficiency - Natural Gas
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Avista Corp 2023 Natural Gas IRP 3-16

Energy 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 Chapter 2. 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 3.5, the bars indicate before and after efficiencies in Roseburg,
Oregon in 2023 per Commercial customer while the area chart illustrates before and after
efficiencies per Residential customer. These totals include the average customer monthly
demand and all end uses to illustrate the energy needed on the electric grid versus the
natural gas system.

Figure 3.5: Energy Conversion Efficiency therms to kWh
Roseburg, Oregon

Conversion Costs
Conversion costs can vary widely by study, location, building size, and structure. Avista
used a study by Home Innovation Research Labs10 to understand estimated costs by
area to help address these ranges. Although the study provides an estimate by major
area, no areas were in the Avista natural gas service territory. To help account for these
wide-ranging study estimates, Avista considered the generic cost “total to a remodeler”.
The low-cost conversion is 50% of this estimated remodel cost and the high cost of

10 Cost and Other Implications of Electrification Policies on Residential Construction, February 2021
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Avista Corp 2023 Natural Gas IRP 3-17

conversion is 150%. This cost information from this study is illustrated in Figure 3.6 along
with the specific efficiency considerations.

Incentives and grants are estimated based on known programs such as the Inflation
Reduction Act which is discussed further in Chapter 5. These costs are treated as being
removed from the overall conversion cost. Also, these conversion costs are estimated to
be recovered over a 5- 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 is removed from the
total before the monthly payment is estimated.

Figure 3.6: Estimated Conversion Costs

Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-18

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 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. This 3% estimate is broken out as 2% inflation and
1% for new transmission and distribution projects. The Washington territory estimates
include 75% of natural gas customers moving to Avista for their electricity needs and 25%
lost to other public power providers such as Inland Power & Light. The assumed
escalation curves for energy per kWh are included in Figure 3.7. Base costs are not
included as it is assumed a gas customer is currently using the local electric provider.

Figure 3.7: Electric Rate Assumption by Area by Class

Rate Impact
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 3.8. 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.

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Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-19

Figure 3.8: Conversion Costs and Energy Costs for Space Heat
Washington Residential

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.

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Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-20

Levelized Costs
The figures below (Figure 3.9 to 3.12) illustrate the final costs used in the model by end
use and class.

Figure 3.9: Space Heat Levelized Costs by Area for Residential Electrification

Figure 3.10: Water Heat Levelized Costs by Area for Residential Electrification

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Chapter 3: Demand Side Resources

Avista Corp 2023 Natural Gas IRP 3-21

Figure 3.11: Space Heat Levelized Costs by Area for Commercial Electrification

Figure 3.12: Water Heat Levelized Costs by Area for Commercial Electrification

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Avista Corp 2023 Natural Gas IRP 3-22

This Page Is Intentionally Left Blank
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-1

4. Current Resources and New Resource Options

This chapter discusses fuel supply options to meet future net energy demand. Avista’s
objective is to provide reliable natural gas service at reasonable prices. To help achieve
this objective, Avista evaluates a variety of supply-side resources and attempts to build a
diversified natural gas supply portfolio. The resource acquisition and commodity
procurement programs resulting from the evaluation of physical and financial risks,
market-related risks, and procurement execution risks; and identifies methods to mitigate
these risks.

Avista manages natural gas procurement and related activities on a system-wide basis
with several regional supply options available to serve core customers. Supply options
include firm and non-firm supplies, firm, and interruptible transportation on six interstate
pipelines, and storage. Because Avista’s core customers span three states, the diversity
of delivery points and demand requirements adds to the options available to meet
customers’ needs. The utilization of these resources varies depending on demand and
operating conditions. This chapter discusses the available regional commodity resources
and Avista’s procurement plan strategies, the regional pipeline resource options available
to deliver the commodity to customers, and the storage resource options available to
provide additional supply diversity, enhanced reliability, favorable price opportunities, and
flexibility to meet a varied demand profile. Carbon reducing supplies, such as renewable
natural gas (RNG) and hydrogen (H2) are also considered.

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 areas of the Northeast and Southern United States. This
supply is serving an increasing amount of demand in the population heavy areas in the
middle and eastern portions of Canada and the U.S displacing supplies previously
delivered from the Western Canadian Sedimentary Basis (WCSB).

Current forecasts show a long-term regional price advantage for Western Canada and
Rockies natural gas basins as the need for this gas diminishes. High 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 demand addition to North American supply. The Canadian project is known as
LNG Canada and is in Kitimat B.C. This facility is one of the largest investments in
Canadian history and is currently under construction. Its initial capacity is, roughly 1 Bcf
per day, but contains an option for up to 3.5 Bcf per day in total. Additionally, WoodFibre
LNG located in Squamish, BC will come online in 2027 removing potentially 0.3 Bcf from
supply to the Pacific Northwest. The large increase of natural gas demand by either of
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-2

these facilities moving forward could cause pressure on commodity prices with the limited
infrastructure in the Pacific Northwest. An LNG facility in Oregon known as Jordan Cove
was approved by FERC, however, was officially abandoned in December 2021 due to the
continued uncertainties around state environmental permits.

Exports to Mexico continue to impact US natural gas demand forecasts. In 2013, Mexico
reformed its energy sector allowing new market participants, innovative technologies, and
foreign investment. This market reformation opened new opportunities for natural gas
export to Mexico. Since these market changes, Mexican imports which were historically
less than 2 Bcf per day have more than doubled to over 5.5 Bcf per day on average.

Regional Market Hubs
There are numerous regional market hubs in the Pacific Northwest where natural gas is
traded extending from the two primary basins. These regional hubs are typically located
at pipeline interconnects. Avista is located near, and transacts at, most of the Pacific
Northwest regional market hubs, enabling flexible access to geographically diverse
supply points. These supply points include:

• AECO – The AECO-C/Nova Inventory Transfer market center located in Alberta is
a major connection region to long-distance transportation systems 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 percent
of Canada's natural gas.
• Rockies – This pricing point represents several locations on the southern end of
the NWP system in the Rocky Mountain region. The system draws on Rocky
Mountain natural gas-producing areas clustered in areas of Colorado, Utah, New
Mexico, and Wyoming.
• Sumas/Huntingdon – The Sumas, Washington pricing point is on the
U.S./Canadian border where the northern end of the NWP system connects with
Enbridge’s Westcoast Pipeline and predominantly markets Canadian natural gas
from Northern British Columbia.
• Malin – This pricing point is at Malin, Oregon, on the California/Oregon border
where TransCanada’s Gas Transmission Northwest (GTN) and Pacific Gas &
Electric Company connect.
• Station 2 – Located at the center of the Enbridge’s Westcoast Pipeline system
connecting to northern British Columbia natural gas production.
• Stanfield – Located near the Washington/Oregon border at the intersection of the
NWP and GTN pipelines.
• Kingsgate – Located at the U.S./Canadian (Idaho) border where the GTN pipeline
connects with the TransCanada Foothills pipeline.

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 NYMEX futures contracts.
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-3

Figure 4.1 shows historic natural gas prices for first-of-month index physical purchases
at AECO, Station 2, Rockies, and Henry Hub. The figure has changed in recent years
due to an alteration in flows of natural gas specifically coming from Western Canada.

Figure 4.1: Monthly Index Prices

Northwest regional natural gas prices typically move together; however, the basis
differential can change depending on market or operational factors. This includes
differences in weather patterns, pipeline constraints, and the ability to shift supplies to
higher-priced delivery points in the U.S. or Canada. By monitoring these price shifts,
Avista can often purchase at the lowest-priced trading hubs on a given day, subject to
operational and contractual constraints.

Liquidity is generally sufficient in the day-markets at most Northwest supply points. AECO
continues to be the most liquid supply point, especially for longer-term transactions.
Sumas has historically been the least liquid of the four major regional supply points
(AECO, Rockies, Sumas, and Malin). This illiquidity contributes to generally higher
relative prices in the high demand winter months.

Avista procures natural gas 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 the supply can be cut for reasons other than force majeure conditions.
• Fixed versus Floating Pricing: The agreed-upon price for the delivered gas may
be fixed or based on a daily or monthly index.
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Avista Corp 2023 Natural Gas IRP 4-4

• Physical versus Financial: Certain counterparties, such as banking institutions,
may not trade physical natural gas, but are still active in the natural gas markets.
Rather than managing physical supplies, those counterparties choose to transact
financially rather than physically. Financial transactions provide another way for
Avista to financially hedge price.
• Load Factor/Variable Take: Some contracts have fixed reservation charges
assessed during each of the winter months, while others have minimum daily or
monthly take requirements. Depending on the specific provisions, the resulting
commodity price will contain a discount or premium compared to standard terms.
• Liquidated Damages: Most contracts contain provisions for symmetrical penalties
for failure to take or supply natural gas.

For this IRP, 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 LNG, and policies towards the continued
use of natural gas. These factors, in addition to more stringent renewable energy
standards and increased need for natural gas-fired generation to back up such resources,
are contributing to the rapidly changing natural gas environment. The uncertainty in
predicting future events and trends requires modeling a range of forecasts.

Many additional factors influence natural gas pricing and volatility, such as regional supply
and demand issues, weather conditions, storage levels, natural gas-fired generation,
infrastructure disruptions, and infrastructure additions, such as new pipelines and LNG
terminals. 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 does 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 4.2 depicts the annual average prices of these combined forecasts in nominal
dollars and includes the expected price resulting from a blending technique.

Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-5

Figure 4.2: Henry Hub Forecasted Price (Nominal $/Dekatherm)

Expected prices at Henry Hub were derived through a blend of forecasts from four
sources, including the New York Mercantile Exchange (NYMEX) forward strip on July 26,
2022, the Energy Information Administration’s (EIA) 2022 Annual Energy Outlook (AEO),
and two reputable market consultants. Combining multiple forecasts improves the
accuracy of our model based on the aggregate market knows more than any single entity
or model.

The weightings applied to each source vary throughout the twenty-year forecasting
horizon. Due to the high volume of market transactions, expected prices align completely
with those of the NYMEX forward strip in the first two years. From 2025 through 2027,
market activity and speculation on the NYMEX deteriorate significantly, so forecasts from
the other three sources, proportionally, are applied incrementally more weighting. By the
year 2028, and through the end of our forecasting horizon, the expected price is the result
of an equally weighted blend of forecasts from the EIA’s AEO and our two market
consultants. The specific weightings applied are described in Table 4.1 and the resulting
annual average expected price at Henry Hub is depicted in Figure 4.3 below.

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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-6

Table 4.1 : Price Blend Methodology

Years Price Blend Methodology
2023 & 2024 forward price only
2025 75% forward price / 25% average consultant forecasts
2026 50% forward price / 50% average consultant forecasts
2027 25% forward price / 75% average consultant forecasts
2028 - 2042 100% average consultant forecasts

Figure 4.3: Expected Price with Allocated Price Forecast

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
stochastic analysis of 500 possible futures were modeled based on the expected price
forecast. Each future contains unique monthly price movements throughout the twenty-
year forecasting horizon. With the assistance of the TAC, Avista selected the 95th and
25th highest prices in each month from the stochastic results to determine high and low-
price curves, respectively. The high, expected, and low-price curves in nominal dollars
are illustrated in Figure 4.4.

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NYMEX EIA/AEO Consultant 1 Consultant 2 Expected Price
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-7

Figure 4.4: Henry Hub Forecasts for IRP Low/ Expected/ High Forecasted Price

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 a large portion of 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 the Henry Hub with a positive or negative basis differential. Of the two
market consultants Avista uses, only one forecasts basis pricing at the gas hubs modeled
throughout the twenty-year horizon.

The natural gas hubs at Sumas, AECO, and the Rockies (and other secondary regional
market hubs) determine Avista’s costs. Prices at these points typically trade at a discount
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
such as Seattle, WA and Portland, OR. Figure 4.5 below shows the resulting regional
prices as compared to the Henry Hub and Figure 4.6 shows the resulting price distribution
for AECO for the 500 future simulations

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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-8

Figure 4.5: Regional Price as a compared to the Henry Hub Price

Figure 4.6: AECO - $ per Dth (500 Draws)

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
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Henry Hub AECO Malin Rockies
Stanfield Station 2 Sumas
Average 4.87$
Min 0.57$
Max 35.69$
Median 4.49$
5th %2.54$
95th %8.58$
Std. Dev.1.92$
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-9

(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 4.7).

Figure 4.7: Regional Pipeline and Storage Capacity

Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-10

The major pipelines servicing the region include:

• Williams - Northwest Pipeline (NWP):
A natural gas transmission pipeline serving the Pacific Northwest moving natural
gas from the U.S./Canadian border in Washington and from the Rocky Mountain
region of the U.S.
• TransCanada Gas Transmission Northwest (GTN): A natural gas transmission
pipeline originating at Kingsgate, Idaho, (Canadian/U.S. border) and terminating
at the California/Oregon border close to Malin, Oregon.
• TransCanada Alberta System (NGTL): This natural gas gathering and
transmission pipeline in Alberta, Canada, delivers natural gas into the
TransCanada Foothills pipeline at the Alberta/British Columbia border.
• TransCanada Foothills System: This natural gas transmission pipeline delivers
natural gas between the Alberta - British Columbia border and the Canadian/U.S.
border at Kingsgate, Idaho.
• TransCanada Tuscarora Gas Transmission: This natural gas transmission
pipeline originates at Malin, Oregon, and terminates at Wadsworth, Nevada.
• Enbridge - Westcoast Pipeline: This natural gas transmission pipeline originates
at Fort Nelson, British Columbia, and terminates at the Canadian/U.S. border at
Huntington, British Columbia/Sumas, Washington.
• El Paso Natural Gas - Ruby pipeline: This natural gas transmission pipeline
brings supplies from the Rocky Mountain region of the U.S. to interconnections
near Malin, Oregon.

Avista has contracts with all the above pipelines (with the exception of Ruby Pipeline) for
firm transportation to serve core customers. Table 4.2 details the firm
transportation/resource services contracted by Avista. These contracts are of different
vintages with different expiration dates; however, all have the right to be renewed by
Avista. This gives Avista and its customer’s available capacity to meet existing core
demand now and in the future.

Table 4.2: Firm Transportation Resources Contracted (Dth/Day)

Avista North Avista South
Firm
Transportation Winter Summer Winter Summer
NWP TF-1 157,869 157,869 42,699 42,699
GTN T-1 100,605 75,782 42,260 20,640
NWP TF-2 91,200 2,623
Total 349,674 233,651 87,582 63,339
Firm Storage Resources - Max Deliverability
Jackson Prairie 346,667 54,623

*Represents original contract amounts after releases expire
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-11

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
from the facility itself. Figure 4.8 illustrates the direct-connect pipeline network relative to
Avista’s supply sources and service territories.1

Figure 4.8: Direct-Connect Pipelines

Supply-side resource decisions focus on where to purchase natural gas and how to
deliver it to customers. Each LDC has distinct service territories and geography relative
to supply sources and pipeline infrastructure. Solutions 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 to likely bear most of the
incremental costs.

1 Avista has a small amount of pipeline capacity with TransCanada Tuscarora Gas Transmission, a natural
gas transmission pipeline originating at Malin, Oregon, to service a small number of Oregon customers
near the southern border of the state.
Roseburg
Medford
SUMAS
ROCKS
Stanfield
NWP GTN
Washington & Idaho
LaGrande
JP
Storage
Malin
Klamath
Falls
AECO
Kingsgate Station 2
Sumas
Rockies
Roseburg &
Medford
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-12

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
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 Avista’s service territories.

The rates used in the planning model start with filed rates currently in effect (See
Appendix 4.1 – Current Transportation/Storage Rates and Assumptions). Forecasting
future pipeline rates is challenging. Assumptions for future rate changes are the result of
market information on comparable pipeline projects, prior rate case experience, and
informal discussions with regional pipeline owners. Pipelines will file to recover costs at
rates equal to their cost of service.

NWP and GTN also offer interruptible transportation services. Interruptible transportation
is subject to curtailment when pipeline capacity constraints limit the amount of natural gas
that may be moved. Although the commodity cost per dekatherm transported is generally
the same as firm transportation, there are no demand or reservation charges in these
transportation contracts. Avista does not rely on interruptible capacity to meet peak day
core demand requirements.

Avista's transportation acquisition strategy is to contract for firm transportation to serve
core customers on a peak day in the planning horizon. Since contracts for pipeline
capacity are often lengthy and core customer demand needs can vary over time,
determining the appropriate level of firm transportation is a complex analysis. The
analysis includes the projected number of firm customers and their expected annual and
peak day demand, opportunities for future pipeline or storage expansions, and relative
costs between pipelines and upstream supplies. This analysis is done on semi-annual
basis and through the IRP. Active management of underutilized transportation capacity
either through the capacity release market or engaging in optimization transactions to
recover some transportation costs, keeps Avista’s portfolio flexible while minimizing costs
to customers. Timely analysis is also important to maintain an appropriate time cushion
to allow for required lead times should the need for securing new capacity arise (See
Chapter 6 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 to meet firm customer demand in a reliable and
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-13

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’s utilization and provide products that no individual component can
satisfy. These products provide more cost recovery of the fixed charges incurred for the
resources. Another strategy to mitigate transportation costs is to participate in the daily
market to assess if 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 Resources
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;
• 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 optimization of assets directly reduce customers monthly billing.

Jackson Prairie Storage (JP)
Avista is one-third owner, with Williams (NWP2) and Puget Sound Energy (PSE) of the
Jackson Prairie Storage Project for the benefit of its core customers in all three states.
Jackson Prairie Storage is an underground reservoir facility located near Chehalis,
Washington approximately 30 miles south of Olympia, Washington. The total working
natural gas capacity of the facility is approximately 25 Bcf. Avista’s current share of this
capacity for core customers is approximately 8.5 Bcf and includes 398,667 Dth of daily
deliverability rights. Besides ownership rights, Avista leased an additional 95,565 Dth of

2 Northwest Pipe
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-14

Jackson Prairie capacity with 2,623 Dth of deliverability from NWP to serve Oregon
customers.

Incremental Supply-Side Resource Options
Avista’s existing portfolio of supply-side resources provides a mix of assets to manage
demand requirements for average and peak day events. Avista monitors the following
potential resource options to meet future requirements in anticipation of changing demand
requirements. When considering or selecting a transportation resource, the appropriate
natural gas supply pairs with the transportation resource and the PLEXOS® model prices
the resources accordingly.

Capacity Release Recall
Pipeline capacity not utilized to serve core customer demand is available to sell to other
parties or optimized through daily or term transactions. Released capacity is generally
marketed through a competitive bidding process and can be on a short-term (month-to-
month) or long-term basis. Avista actively participates in the capacity release market with
short-term and long-term capacity releases. Avista assesses the need to recall capacity
or extend a release of capacity on an on-going basis. The IRP process evaluates if or
when to recall some or all long-term releases.

Existing Available Capacity
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
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-15

Avista’s service territory, this storage cannot be an incremental firm peak serving
resource.

Jackson Prairie
Jackson Prairie is a potential resource for expansion opportunities. Any future storage
expansion capacity does not include transportation and therefore cannot be considered
an incremental peak day resource. However, Avista will continue to look for exchange
and transportation release opportunities 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-Owned Liquefaction LNG
Avista could construct a liquefaction LNG facility in the service area. Doing so could use
excess transportation during off-peak periods to fill the facility, avoid tying up
transportation during peak weather events, and it may avoid additional annual pipeline
charges.

Construction would depend on regulatory and environmental approval as well as cost-
effectiveness requirements. Preliminary estimates of the construction, environmental,
right-of-way, legal, operating and maintenance, required lead times, and inventory costs
indicate company-owned LNG facilities have significant development risks. Due to the
changing direction in policy and fossil fuels, Avista did not model this resource in the
current IRP.

Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-16

Alternative Fuel Supply 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 4.3.

Table 4.3: Carbon Intensity4

Source
Current Carbon
Intensity
(g CO2e/MJ)
Estimated Percent of
Carbon reduction as
compared to natural gas
Natural Gas 78.37
Landfill 46.42 41%
Dairy -276.24 -452%
Wastewater 19.34 75%
Solid Waste -22.93 -129%

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 geographically as
understanding exact location and instruments will be modeled in a detailed manner.

RNG projects are unique, so reliable cost estimates are difficult to obtain. However, Avista
has released a Request For Proposal (RFP) for RNG resources in Q4 of 2022 and pricing
will come into focus for environmental attributes or as a bundled product including both
energy and the environmental attributes. Project sponsorship has many complex issues,
and the more likely participation in such a project is as a long-term contracted purchaser.
Avista considered biogas as a resource in this planning cycle and depending on the
location of the facility it may be cost effective. This is especially the case when found
within Avista’s internal distribution system where transportation and fuel costs can be
avoided. For more information about RNG and its potential uses in energy policy within
Avista territories please see Chapter 5.

3 https://www.ipcc.ch/
4 California Air Resources Board
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-17

RNG Program Considerations
As Avista prepares to move forward with RNG, some of the primary considerations given
are as follows:
• Evaluate available RNG procurement options.
• Pursue potential RNG development opportunities from local RNG feedstock
resources under new legislation (Washington 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
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
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-18

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 that can be utilized for a cleaner
future by transitioning to cleaner fuel and keeping the pipeline infrastructure.

Project Evaluation - Build or Buy
Avista recognizes the two primary options to procure RNG; build RNG project(s) or buy
RNG. In the build scenario, new RNG facilities are developed, and the costs are
recovered the through General Rate Case. Avista can also buy RNG from other RNG
producers and pass the costs through the Gas Purchase Adjustment (GPA).

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.

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
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 LCFS5 and RIN6 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

5 https://ww2.arb.ca.gov/our-work/programs/low-carbon-fuel-standard
6.https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-
renewable-fuel-standard
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-19

supply RNG under a longer-term purchase at a lower price. Figure 4.9 illustrates the
number of participants by state in Avista’s voluntary RNG program, as of November 2022

Figure 4.9: Participants by State

Cost Effective Evaluation Methodology
Avista’s methodology utilizes costs for projects on a levelized basis as compared to other
resources as found in the Plexos model for the IRP. Incorporating just the attribute of
RNG requires a pairing with the energy such as brown gas or gas that has no associated
environmental attribute. To date, the methodology shown is derived from OPUC Docket
UM2030, also referenced in the OPUC Senate Bill 98 rulemaking as described in Chapter
5. The evaluation method shown herein is subject to input, refinement, and
reconsideration (Figure 4.10 and Figure 4.11). In-depth descriptions of the calculations
and components used in the Avista Renewable Resource Development and Procurement
Decision Tree are in Appendix 5.

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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-20

Figure 4.10: Avista RNG Development and Procurement Decision Tree – Part 17

7 The Avista Renewable Resource Development and Procurement Decision Tree described above is a
work in progress and is subject to change at any time.
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-21

Figure 4.11: Avista RNG Development and Procurement Decision Tree – Part 2

Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-22

Environmental Attribute Tracking
Oregon Senate Bill 98 specifies M-RETS8 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)9 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 are based on the unknowns as it 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.

Developing a generic cost for RNG based on feedstock will require several assumptions
as each specific RNG project will have its own capital development costs. Each RNG
project will vary in size, location, and distance to interconnection 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.

RNG costs can deviate greatly by source, location, and capital costs. These RNG costs
are considered by research done for Avista by Black and Veach. This paper considers
cost estimates for averages by RNG type and Hydrogen project size. RNG is considered
an option at increments of twenty environmental attributes known as Renewable Thermal
Credits in the PLEXOS model. To bridge the gap between ownership or purchasing from
a producer, it was made available in the model to assume a quantity taken in a given year
carries forward thru the end of the study. Price estimates are illustrated in Figure 4.12
and assume both the RTC and brown gas as a bundled price. It should be noted that
RTCs can be purchased separately from the energy. The current RFP should help value
RTCs compared with a bundled product.

8 https://www.mrets.org/
9.https://www.epa.gov/renewable-fuel-standard-program/renewable-identification-numbers-rins-under-
renewable-fuel-standard
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-23

Figure 4.12: RNG Price by Source (nominal $)

Hydrogen
Hydrogen (H2) is a fuel source with a long history and a 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 renewables (green H2). With
expanding renewable electricity production, the ability to create green H2 from this energy
is moving from concept to market throughout the world. Some drawbacks to hydrogen
include needing 3 times the volume to provide the same energy as natural gas. With a
maximum blend rate in the pipelines assumed at 20%10, the energy blend can reduce
current pipeline capacity. 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
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 as shown in
Figure 4.13. Further, implications for demand from highly intensive processes altering the
availability of supply have not been studied at this time.

10 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.html
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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-24

Figure 4.13: Production Types of Hydrogen:

The high cost of hydrogen has been the primary barrier to an accelerated use and
adoption. Maturation of these technologies is assumed based on the federal policy known
as Inflation Reduction Act (IRA) and other potential state and county policy. Cost
estimates include a reduction from these renewable energy technologies as seen in wind
and solar11. Incentives from the IRA are assumed in these costs at a full level of $3 per
kg of green hydrogen. Further details of the IRA are discussed in Chapter 5. Several
studies12 were considered to value the cost of green hydrogen in the model as depicted
in Figure 4.14. These costs are assumed to be located at or near load centers in Avista
owned distribution.

11.https://www.lazard.com/perspective/levelized-cost-of-energy-levelized-cost-of-storage-and-levelized-
cost-of-hydrogen/
12 Lazard, Black & Veatch, Bloomberg
Grey Brown Yellow
Blue Green Pink Turquoise

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No

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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-25

Figure 4.14: Green Hydrogen Cost Estimates

Synthetic Methane
Synthetic methane is a fuel beginning to come into focus as an option for cleaner supply
side resources. This fuel can be used in the current natural gas system infrastructure
without any upgrades or alterations as it is, in essence, natural gas. The process would
use a form of carbon capture either directly from the air or from waste and combines
green hydrogen and reacted to create synthetic methane. The potential for new sources
of grants, loans, or funds from programs such as the CCA, CPP or IRA should help drive
the costs of these sources further down as seen in solar and wind projects over the past
30 years. The potential size of this resource is limited to the quantify of hydrogen
available, a carbon source, and cost. Depending on if those elements are available, the
economic synthetic methane has the potential to supply a 1:1 conversion from the natural
gas from fossil sources. This fuel can also help bridge the gap for excess electricity and
act as a storage of energy to a period of higher demand. Carbon capture costs are
estimated between $94 and $414 per MTCO2e depending on source and technology13.
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 4.15.
Finally, a summary of all new resource options is illustrated in Table 4.4.

13 Science Direct, Science Daily
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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-26

Figure 4.15: Synthetic Methane cost estimates

Table 4.4: All resource price comparison $/Dth

Year Hydrogen Dairy Food
Waste LFG Wastewater Synthetic
Methane AECO
2025 $35.43 $36.84 $50.43 $9.62 $16.68 $48.35 $3.43
2030 $25.20 $41.05 $56.15 $10.72 $18.54 $32.90 $3.03
2035 $19.05 $45.72 $62.49 $11.93 $20.60 $30.48 $3.55
2040 $16.09 $50.92 $69.56 $13.28 $22.91 $23.13 $4.19
2045 $12.19 $56.71 $77.43 $14.79 $25.47 $14.84 $5.05

Alternative Fuel Supply Price Risk
While weather is an important driver for the IRP, price is also important. As seen in recent
years, significant price volatility can affect the portfolio. In deterministic modeling, a single
price curve for each scenario is used for analysis. There is risk that the price curve in the
scenario will not reflect actual results.

Avista used Monte Carlo simulation to test the portfolio and quantify the risk to customers
when prices do not materialize as forecast. Avista performed a simulation of 500 draws,
varying prices, to investigate whether the PRS Case total portfolio costs from the
deterministic analysis is 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 4.16 to
Figure 4.21 show the average yearly price per dekatherm, per draw and resource, for
each of the 500 draws. Statistics are also provided with each histogram and represent
the raw data results.

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Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-27

Figure 4.16: RNG Landfill RNG - $ per Dth (500 Draws)

Average 11.76$
Min 7.62$
Max 24.20$
Median 11.49$
5th %8.71$
95th %15.84$
Std. Dev.2.30$
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-28

Figure 4.17: Dairy RNG - $ per Dth (500 Draws)

Figure 4.18: Food Waste RNG - $ per Dth (500 Draws)

Average 45.18$
Min 29.54$
Max 111.03$
Median 44.02$
5th %33.36$
95th %61.13$
Std. Dev.9.25$
Average 61.69$
Min 40.31$
Max 150.62$
Median 60.13$
5th %45.60$
95th %83.20$
Std. Dev.12.47$
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-29

Figure 4.19: Wastewater Treatment RNG - $ per Dth (500 Draws)
Figure 4.20: Hydrogen (500 Draws)

Average 20.34$
Min 13.24$
Max 48.60$
Median 19.83$
5th %15.08$
95th %27.41$
Std. Dev.4.07$
Average 22.46$
Min 10.04$
Max 265.80$
Median 19.44$
5th %12.23$
95th %38.04$
Std. Dev.8.84$
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-30

Figure 4.21: Synthetic Methane - $ per Dth (500 Draws)

Avista’s Natural Gas Procurement Plan
Avista’s foundational purpose/goal of the natural gas procurement plan is to provide a
diversified portfolio of reliable supply while at the same time managing 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. The
Avista procurement plan seeks to acquire natural gas supplies while reducing exposure
to short-term price and load volatility. This is done by utilizing a combination of strategies
to reduce the impacts of changing natural gas prices in a volatile market. A portion of
hedges will be focused on the concentration risk of fixed-price natural gas purchases by
utilizing Hedge Windows, and another portion of hedges will target reducing risk in a
volatile market by utilizing Risk Responsive methods. This allows Avista to set a risk level
to help reduce exposure to events outside of our control such as the Energy Crisis in the
Average 31.41$
Min 12.35$
Max 241.22$
Median 29.11$
5th %15.45$
95th %52.47$
Std. Dev.11.97$
Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-31

early 2000’s or the Enbridge pipeline rupture in 2018 or most recently the COVID-19
pandemic and the oil price collapse.

Hedge transactions may be executed for a period of one-month through thirty-six months
prior to delivery period and are for the Local Distribution Customer (LDC) only. Due to
Avista’s geographic location, transactions may be executed at different supply basins in
order reduce our overall portfolio risk. This procurement plan is disciplined, yet flexible,
allowing for modifications due to changing market conditions, demand, resource
availability, or other opportunities. Should economic or other factors warrant, any material
changes are communicated to senior management and 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.

Market-Related Risks and Risk Management
There are several types of risk and approaches to risk management. The 2023 IRP
focuses on three areas of risk: the financial risk of the cost of natural gas system fuel
options to supply customers will be unreasonably high or volatile, emissions compliance
cost and options in Oregon and Washington and the physical risk that there may not be
enough natural gas system resources (either transportation capacity or the commodity)
to serve core customers.
Avista’s Risk Management Policy describes the policies and procedures associated with
financial and physical risk management. The Risk Management Policy addresses issues
related to management oversight and responsibilities, internal reporting requirements,
documentation and transaction tracking, and credit risk.

Two internal organizations assist in the establishment, reporting and review of Avista’s
business activities as they relate to management of natural gas business risks:

• The Risk Management Committee includes corporate officers and senior-level
management. The committee establishes the Risk Management Policy and
monitors compliance. They receive regular reports on natural gas activity and meet
regularly to discuss market conditions, hedging activity and other natural gas-
related matters.
• The Strategic Oversight Group coordinates natural gas matters among internal
natural gas-related stakeholders and serves as a reference/sounding board for
strategic decisions, including hedges, made by the Natural Gas Supply
department. Members include representatives from the Gas Supply, Accounting,
Regulatory, Credit, Power Resources, and Risk Management departments. While
the Natural Gas Supply department is responsible for implementing hedge
transactions, the Strategic Oversight Group provides input and advice.

Chapter 4: Current Resources and New Resource Options

Avista Corp 2023 Natural Gas IRP 4-32

Strategic Initiatives
Strategic Initiatives are generally defined as the means a vision is translated into practice.
These initiatives are a group of projects and programs that are outside of the
organizations daily operational activities and help an organization achieve a targeted
performance.

The two primary roles of the Energy Resources Department (including Natural Gas
Supply) is now two-fold:
• Serve Load – Assure adequate and reliable energy supplies for Avista Utilities
natural gas customers.
• Manage Resources – Exercise prudent stewardship of Avista Utilities energy
supply facilities and related Company resources.

A thorough review and filing is done annually by Avista for a retrospective hedging report
submitted to the Washington Utilities and Transportation Commission14 (2022 filing UG-
220670). 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.

14 https://apiproxy.utc.wa.gov/cases/GetDocument?docID=5&year=2022&docketNumber=220670
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-1
5. Policy Issues

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.

Avista’s Environmental Objective
Avista has always been on the forefront of clean energy and innovation. Founded on
clean, renewable hydro power on the banks of the Spokane River, Avista has maintained
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.

Environmental Issues
The evolving and sometimes contradictory nature of environmental regulation from state
and federal perspectives creates challenges for resource planning. The IRP cannot add
renewables or reduce emissions in isolation from topics such as system reliability, least
cost requirements, price mitigation, financial risk management, and meeting changing
environmental requirements. All resource choices have costs and benefits requiring
careful consideration of the utility and customer needs being fulfilled, their location, and
the regulatory and policy environment at the time of procurement.

Natural Gas Greenhouse Gas System Emissions
System emissions include any emission found upstream of the point of combustion and
includes production, processing, transmission, and equipment. This designation becomes
important when placing a tax or cost of emissions on the price per MMBtu. Avista
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-2
assumes these emissions are measured at the standard 100-year Global Warming
Potential (GWP) meaning a 34 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 production1 and 1.0%
rate from the Rockies as calculated in the EIA sinks and emissions estimates. Over the
past five years, nearly 90% of Avista’s natural gas was sourced from Canadian production
leaving roughly 10% of estimated upstream emissions to the Rockies region. The EIA
upstream emissions estimate2 is updated on a yearly basis and will show gains and losses
as they occur as compared to a point in time study. These upstream emissions are
included in the Carbon Intensity and Social Cost of Carbon scenarios as emissions in
Oregon and Washington are governed and valued against the CPP and CCA respectively
other than for energy efficiency as explained in Chapter 3.

The final upstream emissions from methane (CH4) in carbon equivalents add nearly 10.66
pounds per MMBtu as shown in Table 5.1:

Table 5.1: Avista Specific LDC Natural Gas Emissions

Combustion Avista Specific Natural Gas
lbs. GHG/MMBtu lbs. CO2e/MMBtu
CO2 116.88 116.88
CH4 0.0022 0.0748
N2O 0.0022 0.6556
Total Combustion 117.61
Upstream
CH4 0.313406851 10.66
Total 128.27

Table 5.2 illustrates the Global Warming Potential; the Intergovernmental Panel on
Climate Change released their 5th assessment study defining these impacts to global
warming in units of CO2e.

Table 5.2: Global Warming Potential (GWP) in CO2 Equivalent3

Greenhouse
Gas
GWP – 100
Year
GWP – 20
Year
CO2 1 1
CH4 34 86
N2O 298 268

1 as calculated in a study for the Tacoma LNG project
2 Inventory of U.S. Greenhouse Gas Emissions and Sinks | Greenhouse Gas (GHG) Emissions | US EPA
3 From the 5th Assessment of the Intergovernmental Panel on Climate Change
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-3
Local Distribution Pipeline Emissions - Methane Study
In a study led by Washington State University (WSU) and sponsored by the
Environmental Defense Fund (EDF) and others, an estimate of utility pipeline distribution
systems leakage found the overall levels of leakage were around 0.1% to 0.2% of
methane delivered nationwide. The study goes on to state the Eastern regions of the
United States contribute much more methane to the total as compared to the Western
regions, where Western regions account for only 5% of total emissions. The study
theorizes eastern US system’s older infrastructure and material types are the likely culprit,
but also goes on to attribute regulations and better infrastructure and monitoring by
utilities for these decreased Western emissions. It found that “out of 230 measurements,
three large leaks accounted for 50 percent of the total measured emissions from pipelines
leaks. In these types of emission studies, a few leaks accounting for a large fraction of
total emissions are not unusual.”4 Such levels within Avista’s distribution system from July
2019 – June 2022 average 0.51%.

State and Regional Level Policy Considerations
The lack of a comprehensive federal greenhouse gas policy has encouraged states, such
as California, to develop their own climate change laws and regulations. Over the past
few years both 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.

Idaho
Avista does not anticipate any greenhouse gas policies in Idaho for the planning horizon.
Although, Idaho customers are at risk of a federal policy regulating of greenhouse gas
emissions, therefore, this plan includes a risk adder of a federal policy. This risk is
evaluated by the inclusion of a national carbon tax beginning in 2030 and increases yearly
through 2045 as shown in Table 5.3. The national pricing is based on a national energy
consultant’s estimate of a nationally accepted price passed by congress. As implications
from programs in California, Oregon and Washington come into focus, a better idea of
indirect cost impacts will be measured through national or regional natural gas prices.
This may include a lower demand for natural gas with a potential to push against high
natural gas prices and lack of pipeline infrastructure growth.

4 https://methane.wsu.edu
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-4
Table 5.3: National Greenhouse Gas Pricing Forecast

Year $ per MTCO2e
Pre-2030 $0
2030 $12.00
2031 $15.03
2032 $17.69
2033 $20.47
2034 $23.36
2035 $26.38
2036 $29.52
2037 $32.79
2038 $36.19
2039 $39.74
2040 $43.43
2041 $46.63
2042 $50.08

Oregon
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. 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 27-2021, Chapter 340 (effective on December 17, 2021)5. In it,
annual reduction amounts between 2022 and 2035 is equal to 27,000 metric tons of
carbon equivalent (MTCO2e) or 50% of Avista’s natural gas customer’s emissions. In the
following timeframe, 2036 – 2050, nearly 19,000 MTCO2e annually reductions leads to
the final 40% reduction from the program baseline goal leaving a 10% total carbon
emissions equivalent by 2050. This program will require natural gas utilities to meet
annual emissions goals in Oregon as illustrated in Figure 5.1.

5 https://www.oregon.gov/deq/rulemaking/Pages/rghgcr2021.aspx
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-5
Figure 5.1: Oregon Customers Annual Emissions Compliance Cap

DEQ’s final rules declare Avista’s annual carbon compliance levels. Within these final
rules, the CPP directs Avista with compliance responsibility for all emissions from our
infrastructure regardless of customer class or source natural gas. This requirement
includes transport customer class emissions where, historically speaking, Avista only
charges a small fee for use of the distribution system but does not procure the energy or
resources to get this energy to the city gate. As such, the requirement adds an additional
48.81% to Avista’s emissions. Refer to Figure 5.2, for an understanding of emissions by
class in 2022.

Figure 5.2: Oregon Emissions by Class for 20226

6 Emission percentages are from 2022 billed data actuals
703,373
351,687
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Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-6
Program Compliance
DEQ’s rules assume a carbon footprint of 117 pounds per MMBtu for natural gas, but
bundled RNG with renewable thermal credit (RTC) or obtaining just the RTC does not
include any greenhouse gas emissions regardless of its actual emissions intensity profile.
Unlike the California program, 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. Further, RNG does not have to be physically sourced in the state of Oregon, so
the total potential volume drastically increases with the increase in geography. Another
element of the program are 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 available is directly related
to the allowed emissions under the CPP. In years 2022 to 2024 the quantity of CCIs
available is equal to 10 percent of the emissions limit, followed by 15% in 2025 to 2027
and finally 20% of the emissions cap from 2028 going forward as show in Figure 5.3.
Avista must purchase these CCI’s at the nominal prices shown in Figure 5.4.

Figure 5.3: Maximum Available CCI Compared to the Reduction Goal

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Avista Corp 2023 Natural Gas IRP 5-7
Figure 5.4: Community Climate Investment ($ per MTCO2e)

Figure 5.5 combines expected emissions from serving load with natural gas as compared
to the comparative number of CCI instruments available to offset these emissions. In
Figure 5.5, the area above the “CPP Emissions Target” line will require additional
reduction instruments, load reduction, or alternative natural gas sources to meet CPP
goals. The resource mix to meet these carbon emissions cap will be discussed in Chapter
6.

Figure 5.5: Business as Usual Emission Forecast vs. Utility Goal

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Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-8
Oregon Senate Bill 334
Senate Bill 334 was passed in 2017 to help develop, update, and maintain the biogas
inventory available. This includes the sites and potential production quantities available
in addition to the quantity of RNG available for use to reduce greenhouse gas emissions.
This bill will also help promote RNG and identify the barriers and removal of barriers to
develop and utilize RNG. In September 2018 the Oregon Department of Energy issued
the report to the Oregon legislature titled “Biogas and Renewable Natural Gas Inventory.”

Oregon Senate Bill 844
Senate Bill 844 passed in 2013 with rulemaking following OPUC Docket AR 580, with
rules going into effect in December of 2014. This bill directed the OPUC to establish a
voluntary emission reduction program and criteria for the purpose of incentivizing public
natural gas utilities to invest in emission reducing projects providing benefits to their
respective customers. The public utility, without the emission reduction program, would
not invest in the project in the ordinary course of business.

To date, this legislation has not yielded any emission reducing projects. Avista is aware
that Governor Brown’s Executive Order 20-04 has the OPUC reconsidering the
usefulness of SB844.

Oregon 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. In order 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 percent of revenue requirement per year needed
to support potential project investment costs. The bill allows investment in gas
conditioning equipment without RFP process. Per 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 Considerations7
In December 2020 a Washington State Energy Strategy was released as a roadmap
committing Washington to 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

7 https://www.commerce.wa.gov/growing-the-economy/energy/2021-state-energy-strategy/
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-9
Climate Commitment Act
The Washington legislature passed its largest environmental program in 2021, the
Climate Commitment Act (CCA) into state law (RCW 70A.45.020). This CCA is
administered by Washington Department of Ecology with the program beginning January
1, 2023. The CCA creates a state-wide emissions cap and trade program where
emissions 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 5.6 illustrates the CCA coverage by percent of emissions
and industry type for included covered entities.

Figure 5.6: Climate Commitment Act Coverage8

Future participants will be added in 2027 with the inclusion of waste-to-energy plants and
in 2031 with railroad companies, and solar and wind power at the Wild Horse wind farm.
The cap for the CCA reduces emissions beginning 2023 by 7 percent annually until 2030.
The cap decreases by 1.8 percent annually from 2031 to 2042. 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. A summary of the prorata share of this reduction to Avista’s LDC
emissions are shown in Figure 5.7.

8 Washington State Department of Ecology produced graphic
Industrial
3%Refineries
6%
Transportation
35%
Electricity
19%
Natural Gas
11%
Other
1%
Not covered
25%
Covered
Not covered
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-10
Figure 5.7: Avista’s Estimated Annual Emissions Cap

All covered entities are required to obtain allowances or offsets to cover their emissions.
Offsets are projects that reduce, remove, or avoid 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 5 percent of their emissions from general offset
projects and 3% from Tribally support projects. Offsets are below the cap meaning
allowance and offsets are interchangeable and should be procured on a least cost or least
risk basis. Program design elements are intended to provide linkage to similar programs
in other jurisdictions. These offsets drop after this initial timeframe to 4% general offsets
and 2% Tribal offsets going forward starting 2027. Please see Figure 5.8 to understand
potential emissions offsets available to Avista through Offset projects.

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Avista Corp 2023 Natural Gas IRP 5-11
Figure 5.8: Emissions Reductions from Offset Projects

These 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 are not known at this time. The intent of this legislation allows for
the Washington State program to join California and the Quebec markets to increase
“allowance” liquidity possibly as early as 2025. California and Quebec still need to
approve the addition of Washington to their program. The law also focuses on using
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.

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 5.9.

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General Offsets Tribal Offsets
CCA Cap
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-12
Figure 5.9: Expected CCA Allowance Prices

Washington HB 2580
House Bill 2580 was signed by Governor Jay Inslee on March 22, 2018 and became
effective on July 1, 2018 bringing into law a bill to help encourage production of RNG.
This bill requires the Washington State University Extension Energy Program and the
Department of Commerce (DOC) along with the consulting of the WUTC, to submit
recommendations on promoting the sustainable development of RNG. The DOC will
consult with natural gas utilities and other state agencies to explore developing voluntary
gas quality standards for the injection of RNG into natural gas pipeline systems in the
state.

Washington HB 1257
The bill was passed during the 2019 Regular Session, coined the “Building Energy
Efficiency” bill, mandating that each gas company must offer by tariff a voluntary
renewable natural gas service. The bill also allows for LDCs to create an RNG program
to supply a portion of the natural gas it delivers to its customers. This program is subject
to review and approval by the WUTC. With regard to 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.”

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Ecology Estimate
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-13
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.

House Bill 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.

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 thru 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
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-14
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 Chapter 4.

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 that
began construction 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 forecasts 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.

Customer Market study
In the 2021 Natural Gas IRP a recommendation was included, from OPUC, to conduct
market research with Avista customers for sentiments around costs and carbon policies.
“Recommendation 9: Prior to the next IRP, conduct market research to reflect the
willingness of Oregon customers to pay for various carbon reduction strategies. Present
results at a TAC meeting.”

In light of climate policy and the potential impact to all jurisdictions served with natural
gas or electricity by Avista, the study was broadened to understand these elements in
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-15
Idaho, Oregon, and Washington. Some study highlights are below and with the entire
study available on Avista’s IRP website.9

The overall objective of this study was to determine the willingness to pay for the
implementation of clean energy among Avista customers. Establishment of a baseline of
environmental concerns, tradeoffs between bill increases and carbon emissions goals,
explore perceptions specific to natural gas preferences and tradeoffs and perceptions
associated with Avista and investing in carbon-neutral or carbon-free emissions sources.
This survey was delivered through the web with Avista customers and sourced randomly
by email and was conducted in April of 2022. The sample size was 1,100 participants.
Participants were required to be above 18 years of age, responsible for household finance
or utility bill and cannot be employed or affiliated by Avista.

Key Takeaways
Price is Important
“When faced with tradeoffs, price is the prevailing factor. While the majority of customers
find importance in sourcing green or local energy, they are only willing to pay so much.
Anything beyond a 10% monthly bill increase shows significant declines in popularity. If
bill increases to invest in carbon-free or carbon-neutral options are kept below 10%, the
specific energy goal, timeframe, local vs. regional source are less important.” An example
of one question related to price is illustrated in Figure 5.10.

Figure 5.10: Bill Increase and Carbon-Neutral or Carbon-Free Options

9https://www.myavista.com/-/media/myavista/content-documents/about-us/our-company/irp-
documents/natural-gas-irp-documents/avista-irp-clean-energy-research-tac.pdf
Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-16
Some Customers See Beyond Price
“Increases beyond 10% monthly still appeal to a certain subset of customers, particularly
those who place great importance on “green,” and/or when the goal can be achieved
within the next 10 years.” Figure 5.11 provides an example of customers seeing beyond
price.

Figure 5.11: Importance of “Green”

Any increase to invest in “green” energy will alienate some customers.
“Overall, roughly one in five do not find importance in being “green” When evaluating
various green investment options, 17 percent reject all, including more ambitious
outcomes for just a 2 percent increase. Three in ten say they would be likely to seek bill
assistance or consider moving to another state if bill were to increase due to Avista
investing in carbon-free or carbon-neutral energy.”

Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-17
Figure 5.12: An Increased Bill and Possible Actions from Customers

Finally, we have nearly half of our customers that would not consider switching from
natural gas to help reduce carbon emissions. While nearly 75 percent of these customers
agree that eliminating natural gas should be entirely voluntary as shown in Figure 5.13.

Figure 5.13: Customer Concerns with Fuel Switching

Chapter 5: Policy Issues
Avista Corp 2023 Natural Gas IRP 5-18
Equity Considerations
Equity has been a newer piece of the IRP process in Washington, for electric investor-
owned utilities, as introduced from Clean Energy Transformation Act (CETA) and other
legislation or WUTC policies. Equity focuses on the energy justice, through metrics, to
consider benefits and burdens of living near resources. Avista intends to incorporate
increased equity considerations in the 2025 natural gas IRP and utilize lessons from our
electric IRP process to assist in the development of metrics and use in analytics.

Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-1

6. Preferred Resource Strategy

This chapter combines the previously discussed IRP components within the PLEXOS®
model to determine resource deficiencies during the 20 plus years planning horizon. The
foundation for integrated resource planning is the criteria used for developing demand
forecasts. The weather planning standard is updated in this IRP. The new planning
standard has Avista moving away from coldest day on record and into a 99% probability
of a daily temperature occurring. This new standard has been combined with forecasted
future weather data for each planning area as discussed in Chapter 2. Avista plans to
serve the expected peak day in each demand region with firm resources. Firm resources
include natural gas and distributed renewable supplies, firm pipeline transportation, and
storage resources. In addition to peak requirements, Avista also plans for non-peak
periods such as winter, shoulder months (April and October) and summer demand. The
modeling process includes an optimization for every day of the 20-year planning period.

The IRP assumes on a peak day all interruptible customers have left the system to provide
service to firm customers. Avista does not make firm commitments to serve interruptible
customers, therefore this IRP analysis only includes the firm residential, commercial, and
industrial classes. Using the weather planning standard, a blended price curve of three
studies developed by industry experts, and an academically backed customer forecast all
work together to develop stringent planning criteria.

Forecasted demand represents the amount of energy needed. Delivering this forecasted
demand requires an additional 1% to 3% on both an annual and peak-day basis to
account for additional natural gas supplies purchased primarily for pipeline compressor
station fuel. The range of 1% to 3% (known as fuel), varies depending on the pipeline.
This fuel is used to move the gas from point A on the pipeline to point B or the delivery
point. The FERC and National Energy Board approved tariffs govern the percentage of
required additional fuel supply.

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 and is pressure driven (Chapter 8).

PLEXOS® Planning Model
PLEXOS® is a 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. PLEXOS® 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 given a set of
constraints. The model considers the following variables:

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Avista Corp 2023 Natural Gas IRP 6-2

• Demand data, such as customer count forecasts and demand coefficients 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 including supply basins, revenue
requirements as the key cost metric for all asset additions and prices.
• Natural gas storage options with injection/withdrawal rates, capacities, and costs.
• Energy Efficiency potential.

Figures 6.1 through 6.5 are PLEXOS® network diagrams of Avista’s demand centers and
resources (including supply resource options). This diagram illustrates current
transportation and storage assets, flow paths and constraint points.

Figure 6.1: PLEXOS® Idaho System Map

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Avista Corp 2023 Natural Gas IRP 6-3

Figure 6.2: PLEXOS® Washington System Map

Figure 6.3: PLEXOS® Oregon System Map

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Avista Corp 2023 Natural Gas IRP 6-4

Figure 6.4: PLEXOS® Washington Transport Customer Map

Figure 6.5: PLEXOS® Oregon Transport Customer Map

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Avista Corp 2023 Natural Gas IRP 6-5

The PLEXOS® 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.

PLEXOS® also includes Stochastic modeling and Monte Carlo capabilities to facilitate
price and demand uncertainty modeling and detailed portfolio optimization techniques to
produce probability distributions. The PLEXOS® model is used by LDC’s across the U.S.
and has replaced Avista’ use of SENDOUT®, as it became increasingly outdated for the
current regulatory environment when it comes to greenhouse gas reduction. Figure 6.6
provides a summary view of inputs and modeling flow.
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Avista Corp 2023 Natural Gas IRP 6-6

Figure 6.6: Modeling Workflow Diagram

Process
Model Inputs
Plexos®
Solves least cost resource as a
system
Linear Optimization
Stochastic Analysis
Outputs
Enter all future resource options:•Demand-Side (DSM, DR)•Supply-Side
-RNG-H2-Synthetic methane-Electrification-Other•Compliance mechanisms-CCI
-Allowance-Offset
Scenario Analysis•Customer Counts•Use per customer•Emissions•Risk Analysis•Other
Demand Forecast by area and class•Customer counts•Use per customer per HDD•Expected energy demand
Existing Supply-Side Resources•Costs•Operational Characteristics
Resource Considerations•Resource Cost•Peak vs. Base Load•Lead Time Requirements•Resource Usefulness•“Lumpiness” of Resource Options•Carbon Intensity•Ownvs. contracted
Weather•20 year NOAA average by area
plus Peak Day weather planning standard
Commodity/Compliance Prices•Basis differential•Volatility•Seasonal Spreads•Commodity prices by supply type•Compliance price
Policy•Climate Committment Act•Climate Protection Plans•Company Environmental Goals•Cost of Carbon•Other
Conservation
Potential
Assessment
(CPA)
From AEG and
ETO
Marginal
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Integrated
Resource Plan
Determine Preferred
Resource Strategy
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Avista Corp 2023 Natural Gas IRP 6-7

Stochastic Analysis1
The scenario (deterministic) analysis described earlier in this chapter represents specific
what if situations based on predetermined expected assumptions, including price and
weather. These factors are an integral part of scenario analysis. To understand how each
scenario will respond to cost and risk, through price and weather, Avista applied
stochastic analysis to generate a variety of price and weather events.

Deterministic analysis is a valuable tool for selecting an optimal portfolio yet only
considers one set of data such as the most probably future. The model selects resources
to meet peak weather conditions in each of the 20 years. However, due to the recurrence
of design conditions in each of the 20 years, total system costs over the planning horizon
can be overstated because of annual recurrence of design conditions and the recurrence
of price increases in the forward price curve. As a result, deterministic analysis does not
provide a comprehensive look at future events. Utilizing stochastic simulation and Monte
Carlo simulation in conjunction with deterministic analysis provides a more complete
picture of portfolio variability of price risk and weather created risks.

A deterministic resource mix is performed allowing the model to solve the demand based
on the optimal least cost solution for the system. Avista then performs five stochastic
simulations on the Preferred Resource Strategy (PRS) where PLEXOS® solves for all
five futures at the same time occurring in a single best set of resources to solve the energy
and emissions goals.

Resource Integration
The following sections summarize the comprehensive analysis bringing demand
forecasting and existing and potential supply and demand-side resources together to form
the 20-year, least-cost plan. Chapter 2 describes Avista’s demand forecasting approach.

Avista forecasts eleven 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 gas to an area); Medford (disaggregated into two sub-areas
because of pipeline flow limitations); and Roseburg, Klamath Falls, and La Grande. In
addition to area distinction, Avista also models demand by customer class within each
area. The relevant firm customer classes are residential, commercial, and industrial
customers.

Customer demand is highly weather-sensitive. Avista’s customer demand is not only
highly seasonable, but also highly variable. Figure 6.7 captures this variability showing
firm customer monthly system-wide average demand, minimum demand day observed

1 PLEXOS® uses Monte Carlo simulation to support stochastic analysis, which is a mathematical technique
for evaluating risk and uncertainty. Monte Carlo simulation is a statistical modeling method used to imitate
future possibilities that exist with a real-life system.
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-8

by month, maximum demand day observed in each month, and winter projected peak day
demand for the first year of the PRS forecast as determined in PLEXOS®.

Figure 6.7: Total System Average Daily Load (Average, Minimum and Maximum)

Carbon Policy Resource Utilization Summary
Avista uses an estimated carbon price as an incremental adder to address any potential
policy. Carbon price adders increase the price of a dekatherm of natural gas and impact
resource selections and are summarized in Figure 6.8. Oregon and Washington were
assumed to have a social cost of carbon (SCC) at a 2.5% carbon adder price and based
on carbon tax figures built on the requirement to utilize SCC at 2.5% discount estimates
from the Environmental Protection Agency (EPA), as required by RCW 80.28.395 and
per the 2021 IRP Chapter 9, Recommendation 7. For the State of Idaho, Avista
considered a national carbon tax beginning in 2030 running through the end of study
timeframe in 2045. SCC is used to value energy efficiency (EE) as described in Chapter
3. Compliance to the Climate Commitment Act and Climate Protection Plan (CPP) occurs
through instruments in each program, with the attributed carbon costs of compliance
valued against supply side resources.

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Avista Corp 2023 Natural Gas IRP 6-9

Figure 6.8: Carbon Legislation Sensitivities

Transportation and Storage
Valuing natural gas supplies is a critical first step in resource integration. Equally
important is capturing all costs to deliver the natural gas to customers. Daily capacity of
existing transportation resources (described in Chapter 4) is represented by the firm
resource duration curves depicted in Figures 6.9 and 6.10.

Current rates for capacity are in Appendix 6.1. Forecasting future pipeline rates can be
challenging because of the need to estimate the amount and timing of rate changes.
Avista’s estimates and timing of future pipeline rate increases are based on knowledge
obtained from industry discussions and participation in pipeline rate cases. This IRP
assumes pipelines will file to recover costs at rates equal to increases in GDP (see
Appendix 6.2).

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Avista Corp 2023 Natural Gas IRP 6-10

Figure 6.9: Existing Firm Transportation Resources

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. New to the 2023 IRP is the requirement to meet greenhouse
emissions targets in both Oregon and Washington creating a resource clean energy
deficiency.

Avista acquired most of its upstream pipeline capacity during the deregulation or
unbundling of the natural gas industry. Pipelines were required to allocate capacity and
costs to their existing customers as they transitioned to transportation only service
providers. The FERC allowed a rate structure for pipelines to recover costs through a
Straight Fixed Variable rate design. This structure is based on a higher reservation charge
to cover pipeline costs whether natural gas is transported or not, and a much smaller
variable charge which is incurred only when natural gas is transported. An additional fuel
charge is assessed to account for the compressors required to move the natural gas to
customers. Avista maintains enough firm capacity to meet peak day requirements under
the Expected Case in this IRP. This requires pipeline capacity contracts at levels 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 management simultaneously deploys multiple long-
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Avista Corp 2023 Natural Gas IRP 6-11

and short-term strategies to meet firm demand requirements in a cost-effective manner.
These strategies and plan are discussed in detail in Chapter 4. The resource strategies
addressed are:

• Emissions compliance;
• Pipeline contract terms;
• Pipeline capacity;
• Storage;
• Commodity and transport optimization; and
• Combination of available resources.

Pipeline Contract Terms
Some pipeline costs are incurred whether the capacity is utilized or not. Winter demand
must be satisfied, and peak days must be met. Ideally, capacity could be contracted from
pipelines only for the time and days it is required. Unfortunately, this is not how pipelines
are contracted or built. Long-term agreements at fixed volumes are usually required for
building or acquiring firm transport. This assures the pipeline of long-term, reasonable
cost recovery.

Avista has negotiated and contracted for several seasonal transportation agreements.
These agreements allow volumes to increase during the demand intensive winter months
and decrease over the lower demand summer period. This is a preferred contracting
strategy because it eliminates costs when demand is low. Avista refers to this as a front-
line strategy because it attempts to mitigate costs prior to contracting the resource. Not
all pipelines offer this option. Avista seeks this type of arrangement where available.
Avista currently has some seasonal transportation contracts on TransCanada GTN in
addition to contracted volumes of TF2 on NWP. This is a storage specific contract and
matches up the withdrawal capacity at Jackson Prairie with pipeline transport to Avista’s
service territories. TF2 is a firm service and allows for contracting a daily amount of
transportation for a specified number of days rather than a daily amount on an annual
basis as is usually required. For example, one of the TF2 agreements allows Avista to
transport 91,200 Dth/day for 31 days. This is a more cost-effective strategy for storage
transport than contracting for an annual amount. Through NWP’s tariff, Avista maintains
an option to increase and decrease the number of days this transportation option is
available. More days correspond to increased costs, so balancing storage, transport, and
demand is important to ensure an optimal blend of cost and reliability.

Pipeline Capacity
After contracting for pipeline capacity, its management and utilization determine the
actual costs. The worst-case economic scenario is to do nothing and simply incur the
costs associated with this transport contract over the long-term to meet current and future
peak demand requirements. Avista develops strategies to ensure this does not happen
on a regular basis if possible.
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-12

Capacity Release
Through the pipeline unbundling of transportation, the FERC establishes rules and
procedures to ensure a fair market developed to manage pipeline capacity as a
commodity. This evolved into the capacity release market and is governed by FERC
regulations through individual pipelines. The pipelines implement the FERC’s posting
requirements to ensure a transparent and fair market is maintained for the capacity. All
capacity releases are posted on the pipelines Bulletin Boards and, depending on the
terms, may be subject to bidding in an open market. This provides the transparency
sought by the FERC in establishing the release requirements. Avista utilizes the capacity
release market to manage both long-term and short-term transportation capacity.

For capacity under contract that may exceed current demand, Avista seeks other parties
that may need it and arranges for capacity releases to transfer rights, obligations, and
costs. This shifts all or a portion of the costs away from Avista’s customers to a third party
until it is needed to meet customer demand.

Many variables determine the value of natural gas transportation. Certain pipeline paths
are more valuable, and this can vary by year, season, month, and day. The term, volume
and conditions present also contribute to the value recoverable through a capacity
release. For example, a release of winter capacity to a third party may allow for full cost
recovery; while a release for the same period that allows Avista to recall the capacity for
up to 10 days during the winter may not be as valuable to the third party, but of high value
to us. Avista may be willing to offer a discount to retain the recall rights during high
demand periods. This turns a seasonal-for-annual cost into a peaking-only cost. Market
terms and conditions are negotiated to determine the value or discount required by both
parties.

Avista has several long-term releases, some extending multiple years, providing full
recovery of all the pipeline costs. These releases maintain Avista’s long-term rights to the
transportation capacity without incurring the costs of waiting until demand increases. As
the end of these release terms near, Avista surveys the market against the IRP to
determine if these contracts should be reclaimed or released, and for what duration.
Through this process, Avista retains the rights to vintage capacity without incurring the
costs or having to participate in future pipeline expansions that will cost more than current
capacity.

On a shorter term, excess capacity not fully utilized on a seasonal, monthly, or daily basis
can also be released. Market conditions often dictate less than full cost recovery for
shorter-term requirements. Mitigating some costs for an unutilized, but required resource
reduces costs to our customers.

Segmentation
Through a process called segmentation, Avista creates new firm pipeline capacity for the
service territory. This doubles some of the capacity volumes at no additional cost to
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Avista Corp 2023 Natural Gas IRP 6-13

customers. With increased firm capacity, Avista can continue some long-term releases,
or even reduce some contract levels, if the release market does not provide adequate
recovery. An example of segmentation is if the original receipt and delivery points are
from Sumas to Spokane. Avista can alter this path from Sumas to Sipi, Sipi to Jackson
Prairie, Jackson Prairie to Spokane. This segmentation allows Avista to flow three times
the amount of natural gas on most days or non-peak weather events. In the event of a
peak day, and the transport needs to be firm, the transportation can be rolled back up to
ensure the natural gas will be delivered into the original firm path.

Storage
As a one-third owner of the Jackson Prairie Storage facility, Avista holds an equal share
of capacity (space available to store natural gas) and delivery (the amount of natural gas
that can be withdrawn daily).

Storage allows lower summer-priced natural gas to be stored and used in the winter
during high demand or peak day events. Like transportation, unneeded capacity and
delivery can be optimized by selling into a future higher priced market. This allows Avista
to manage storage capacity and delivery to meet growing peak day requirements when
needed.

The injection of natural gas into storage during the summer utilizes existing pipeline
transport and helps increase the utilization factor of pipeline agreements. Avista employs
several storage optimization strategies to mitigate costs. Revenue from this activity flows
through the annual PGA process.

Commodity and Transportation Optimization
Another strategy to mitigate transportation costs is to participate in the daily market to
assess if unutilized capacity has value. Avista seeks daily opportunities to purchase
natural gas, transport it on existing unutilized capacity, and sell it into a higher priced
market to capture the cost of the natural gas purchased and recover some pipeline
charges. The amount of recovery is market dependent and may or may not recover all
pipeline costs but does mitigate pipeline costs to customers.

Combination of Resources
Unutilized resources like supply, transportation, storage, and capacity can combine to
create products that capture more value than the individual pieces. Avista has structured
long-term arrangements with other utilities that allow available resource utilization and
provide products that no individual component can satisfy. These products provide more
cost recovery of the fixed charges incurred for the resources while maintaining the rights
to utilize the resource for future customer needs.

Resource Utilization Summary
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
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-14

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.

Demand and Deliverability Balance
After incorporating the above data into the PLEXOS® 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 meet firm
customer demand in a reliable and cost-effective manner as described in Chapter 4.

Figures 6.10 and 6.11 provide graphic summaries of the deterministic results for the
Average Scenario and Preferred Resource Strategy (PRS). Average Case demand (black
line) as 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 resources exceed demand needs
over the planning horizon. Considerations as 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 gas in times of need. These resources
vary in ownership by state and area and must match or exceed volume of expected
demand.

Figures 6.12 and 6.13 details peak day demand compared to existing resources. This
demand is also net of energy efficiency savings. Avista is still long transport rights,
consistent with prior IRP expectations. Peak Day criteria is important as it protects our
customers and their structures during extreme weather.

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Avista Corp 2023 Natural Gas IRP 6-15

Figure 6.10: Average Demand Compared to Storage & Transport Rights for
February 28th

Figure 6.11: Average Demand Compared to Storage & Transport Rights for
December 20th

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Avista Corp 2023 Natural Gas IRP 6-16

Figure 6.12: Expected Peak Day Demand Compared to Storage & Transport
Rights for February 28th

Figure 6.13: Expected Peak Day Demand Compared to Storage & Transport
Rights for December 20th

When considering emissions compliance under the CCA and CPP, a different story
emerges when comparing to transportation rights. Greenhouse gas 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 6.14
and Figure 6.15, equivalent emissions from firm customers and transport customers can
be found in the stacked bar chart with the cap for the respective program as illustrated in
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NWP (ID-WA)NWP (OR)JP (ID-WA)
JP (OR)KF Lateral
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-17

by the line. These charts clearly show noncompliance if no actions are taken to offset
emissions or other options per program rules, where the total emissions in the blue and
green bars exceed the cap shown in orange. These shortages occur in 2023 and continue
through the end of the study in 2045. Further study is required to determine demand and
price in an unknown future.

Figure 6.14: Washington Emissions Forecast Compared to CCA Cap

Figure 6.15: Emissions Forecast Compared to CPP Cap

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200,000
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Firm Transport CPP Cap
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-18

New Resource Options and Considerations
All scenarios analyzed in this IRP process contain resource needs based on the climate
policy in Oregon and Washington. These options have been input into the PLEXOS®
model to help solve the energy demand and emissions goals. Table 6.1 highlights supply-
side and demand-side resource options as discussed in prior chapters.

Table 6.1: New Supply-Side and Demand-Side Resource Options

Supply-Side Resource Options Demand-Side Resource Options
Natural Gas + Compliance Instrument in
OR (CCI) and WA (allowance or offset)
Demand Response by program
Green Hydrogen Electrification – Space Heat
Synthetic Methane Electrification – Water Heat
RNG by source (Dairy, Landfill, Solid
Waste, and Waste Water)
Electrification - Other
Natural Gas Energy Efficiency (CPA from AEG and ETO)

Resource cost is the primary consideration when evaluating resource options, although
other factors mentioned below also influence resource decisions. Newly constructed
resources are typically more expensive than existing resources, but existing resources
are in shorter supply. Newly constructed resources provided by a third party, such as a
pipeline, may require a significant contractual commitment. However, newly constructed
resources are often less expensive per unit, if a larger facility is constructed, because of
economies of scale. Resource cost estimates can be found in Chapter 4. A full set of
resource options is provided in Figure 6.16 to help illustrate resource costs in comparison
to one another over time. These costs exclude electrification options as found in Chapter
3, mostly as they skew the chart making the natural gas options difficult to view.

Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-19

Figure 6.16: Resource Options and Costs in PLEXOS Model

Lead Time Requirements
New resource options can take up to five or more years to put in service. Open season
processes to determine interest in proposed pipelines, planning and permitting,
environmental review, design, construction, and testing contribute to lead time
requirements for new facilities. Recalls of released pipeline capacity typically require
advance notice of up to one year. Even energy efficiency programs can require significant
time from program development and rollout to the realization of natural gas savings.

Peak versus Base Load
Avista’s planning efforts include the ability to serve firm natural gas loads on a peak day,
as well as all other demand periods. Avista’s core loads are considerably higher in the
winter than the summer. Due to the winter-peaking nature of Avista’s demand, resources
that cost-effectively serve the winter 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
unique service territories, it is often impossible to deliver resources from a resource
option, such as storage, without acquiring additional pipeline transportation. Pairing
resources with transportation increases cost. Other key factors that can contribute to the
usefulness of a resource are viability and reliability along with carbon intensity. If the
potential resource is either not available currently (e.g., new technology) or not reliable
on a peak day (e.g., firm), they may not be considered as an option for meeting unserved
demand.
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Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-20

“Lumpiness” of Resource Options
Newly constructed resource options are often “lumpy.” 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 new construction,
where lower unit costs are available with larger expansions and the economics of
expansion of existing pipelines or the construction of new resources dictate additions
infrequently. The lumpiness of new resources provides a cushion for future growth.
Economies of scale for pipeline construction provide the opportunity to secure resources
to serve future demand increases. 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
vary, and regional LDCs may find they are competing with other parties to secure firm
resources for customers. RNG resources specifically will have an increased amount of
competition as the drive for carbon-reducing supplies increases with associated policy.

Risks and Uncertainties
Investigation, identification, and assessment of risks and uncertainties are critical
considerations when evaluating supply resource options. For example, resource costs
are subject to degrees of estimation, partly influenced by the expected timeframe of the
resource need and rigor determining estimates, or estimation difficulties because of the
uniqueness of a resource. Lead times can have varying degrees of certainty ranging from
securing currently available transport (high certainty) to building underground storage
(low certainty).

Energy Efficiency Resources
Integration by Price
As described in Chapter 3, Avista determines energy efficiency cost effectiveness without
future energy efficiency programs in the load forecast. This preliminary study provides an
avoided cost curve for both Applied Energy Group (AEG) and 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, Program Administrator Costs Test, Total
Resource Cost Test, and Participant Cost Test. The therm savings and associated
program costs are incorporated into the PLEXOS® model therefore 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. Tables 6.2 and 6.3 show potential energy efficiency savings
in dekatherms for each region from the resource potential for the Expected Case. The
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-21

energy efficiency annual demand served begins to decline after reaching a peak in 2032
as a total system as measures require replacement.

Table 6.2: Annual Demand Served by Energy Efficiency

Table 6.3: Average Daily Demand Served by Energy Efficiency

Case Year Klamath Falls La Grande Medford/Roseburg Oregon Idaho Washington Total System
PRS 2023 8,194 4,466 44,889 57,549 46,414 111,991 273,503
PRS 2024 8,504 4,635 46,586 59,725 52,700 122,712 294,863
PRS 2025 8,864 4,831 48,555 62,249 59,890 137,682 322,070
PRS 2026 9,008 4,909 49,347 63,264 55,234 123,902 305,664
PRS 2027 9,431 5,140 51,661 66,232 64,711 139,450 336,624
PRS 2028 10,110 5,510 55,382 71,002 74,970 152,821 369,795
PRS 2029 10,914 5,948 59,786 76,647 83,106 171,273 407,674
PRS 2030 11,614 6,330 63,622 81,566 89,337 177,730 430,199
PRS 2031 12,288 6,697 67,317 86,302 91,496 175,688 439,788
PRS 2032 12,839 6,997 70,332 90,168 90,704 171,846 442,886
PRS 2033 13,263 7,228 72,656 93,147 85,561 160,872 432,727
PRS 2034 13,521 7,369 74,066 94,955 78,470 146,895 415,276
PRS 2035 13,307 7,252 72,898 93,458 71,431 131,483 389,830
PRS 2036 13,059 7,117 71,535 91,711 64,587 119,970 367,979
PRS 2037 12,805 6,979 70,147 89,930 56,419 107,079 343,358
PRS 2038 12,610 6,872 69,078 88,561 49,196 91,981 318,299
PRS 2039 12,375 6,744 67,793 86,913 43,787 82,345 299,957
PRS 2040 12,210 6,654 66,886 85,750 40,163 76,356 288,019
PRS 2041 12,032 6,557 65,913 84,503 35,109 67,940 272,055
PRS 2042 11,753 6,405 64,384 82,543 34,459 64,851 264,396
Case Year Klamath Falls La Grande Medford/Roseburg Oregon Idaho Washington Total System
PRS 2023 22.45 12.24 122.98 157.67 127.16 306.83 749.32
PRS 2024 23.24 12.66 127.28 163.18 143.99 335.28 805.64
PRS 2025 24.28 13.23 133.03 170.55 164.08 377.21 882.38
PRS 2026 24.68 13.45 135.20 173.33 151.33 339.46 837.44
PRS 2027 25.84 14.08 141.54 181.46 177.29 382.05 922.26
PRS 2028 27.62 15.05 151.32 193.99 204.84 417.54 1,010.37
PRS 2029 29.90 16.30 163.80 209.99 227.69 469.24 1,116.92
PRS 2030 31.82 17.34 174.31 223.47 244.76 486.93 1,178.63
PRS 2031 33.67 18.35 184.43 236.44 250.67 481.34 1,204.90
PRS 2032 35.08 19.12 192.16 246.36 247.83 469.53 1,210.07
PRS 2033 36.34 19.80 199.06 255.20 234.41 440.74 1,185.55
PRS 2034 37.04 20.19 202.92 260.15 214.99 402.45 1,137.74
PRS 2035 36.46 19.87 199.72 256.05 195.70 360.23 1,068.03
PRS 2036 35.68 19.44 195.45 250.58 176.47 327.79 1,005.41
PRS 2037 35.08 19.12 192.18 246.38 154.57 293.37 940.71
PRS 2038 34.55 18.83 189.26 242.63 134.78 252.00 872.05
PRS 2039 33.91 18.48 185.73 238.12 119.97 225.60 821.80
PRS 2040 33.36 18.18 182.75 234.29 109.74 208.62 786.94
PRS 2041 32.97 17.97 180.58 231.51 96.19 186.14 745.36
PRS 2042 32.20 17.55 176.40 226.14 94.41 177.67 724.37
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-22

Preferred Resource Strategy (PRS)
The PRS considers current supply-side resources and new resource options to solve the
energy and carbon program goals. The resources Avista modeled for the current IRP
include five types of RNG, hydrogen, synthetic methane, and demand side options of
demand response (DR) as discussed in Chapter 4, and electrification of major end uses
such as space heat, water heating and cooking detailed in Chapter 3. The cost risk for
each of these selected resources can be found in Chapter 4.2 Electrification end uses are
treated as a resource and if any amount is taken, future years must take this same amount
as a minimum as it’s considered permanent demand loss. Demand Response is treated
in a similar fashion as if a program is selected, program costs, and demand savings must
be used going forward.

To solve for unserved demand and emissions goals, a set of resources options are
available to meet the requirements of energy, capacity and emissions constraints as
determined from these stochastic draws. This stochastic evaluation is a deviation from
prior resource plans and has been introduced to not over procure new resources, while
maintaining compliance to emission reduction programs. Using deterministic results
would create a yearly energy peak and may increase risks in the over investment in
resources. As discussed in Chapter 2, weather and demand will vary as shown
historically, and planning for new resource must be considered on a stochastic basis.

Idaho PRS
The Idaho PRS continues to utilize the least cost natural gas basin, and storage,
combined with energy efficiency to meet energy demand as illustrated in Figure 6.17.
Natural gas will be acquired on a least cost basis from the available hubs as illustrated in
Figure 6.18. 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
amount of pipeline capacity is located.

2 Chapter 4 – Current Supply-Side Resources and New Resource Options.
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-23

Figure 6.17: Idaho Preferred Resource Strategy

Figure 6.18: Natural Gas Basin Least Cost - Idaho

Oregon PRS
Oregon’s PRS has drastically changed as compared to the 2021 IRP. Changes adhere
to the new environmental goals of the CPP and the estimated energy demand. In the
near-term, the new resource need is acquired via a combination of RNG from Landfill Gas
(LFG), Wastewater Treatment Plants (WWTP), energy efficiency, Community Climate
Investments (CCIs), and conventional natural gas. Synthetic methane is added to the
resource mix beginning in the 2030’s, as illustrated in Figure 6.19. Least cost natural gas
basin is illustrated in Figure 6.20. In each figure, the dark blue area at the bottom of the
0
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Stanfield (ID)Station 2 (ID)Sumas (ID)
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-24

chart depicts natural gas with no emissions instrument for compliance, essentially the cap
of the CPP.

Figure 6.19: Oregon Preferred Resource Strategy

Figure 6.20: Natural Gas Basin Least Cost – Oregon

As discussed in Chapter 5, the number of CCIs available to Avista declines with the cap
each year. To backfill these lost CCIs additional resources need to be brought onto the
system on an annual basis through the end of the study timeframe. This will lead to an
increased number of renewable energy sources needed as depicted in Table 6.4.
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RNG - WWTP Natural Gas With CCI DSM
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AECO Malin Rockies Stanfield Station 2 Sumas
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-25

Table 6.4: Average Daily Resource Quantities by Year

Year Natural
Gas -
No CCI
Synthetic
Methane
RNG -
LFG
RNG -
WWTP
Natural Gas
with CCI
(Dth
equivalent)
2023 35,237 - 2,024 196 1,310
2024 33,960 - 3,762 1,460 666
2025 32,568 - 4,619 1,824 955
2026 31,173 - 5,306 1,824 2,095
2027 29,747 - 6,038 1,824 2,681
2028 28,375 - 6,773 1,829 4,923
2029 26,908 - 7,474 1,824 4,613
2030 25,491 138 8,240 1,824 5,028
2031 24,082 517 8,800 1,824 4,748
2032 22,654 5,329 9,208 1,829 4,469
2033 21,219 3,205 9,559 1,823 4,190
2034 19,795 6,229 9,837 1,824 3,910
2035 18,377 8,337 9,918 1,824 3,631
2036 17,405 10,172 9,947 1,827 3,437
2037 16,430 13,210 9,920 1,823 3,244
2038 15,448 11,936 9,920 1,824 3,050
2039 14,462 13,748 9,920 1,824 2,856
2040 13,486 16,507 9,946 1,828 2,663
2041 12,491 17,401 9,920 1,824 2,469
2042 11,523 19,717 9,920 1,824 2,276
2043 10,533 19,778 9,920 1,824 2,082
2044 9,563 21,552 9,947 1,829 1,888
2045 8,597 24,093 9,920 1,824 1,356

CCIs are expected to be a least cost solution when compared to renewable resource
options, due to the ability to pair CCIs with natural gas as a low quantity solution. Low
carbon resource fuels will be needed to serve a consistent demand of energy and
emissions. Also, due to the divergent weather locations, the risk 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 are warmer
climates and do not get the extreme temperatures. Figure 6.21 illustrates the range in
CCIs required given the potential for weather variance. In the near term the CCIs have a
wide range of volumes required. Beginning in 2030, the range disappears as the certainty
of the demand for these instruments in meeting CPP emission compliance is necessary
to procure the entire amount available within the program. Finally, the study points to
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-26

more uncertainty for CCIs as alternative fuels may become more cost effective in the
2042 and beyond time horizon.

Figure 6.21: Community Climate Investment Quantity – (MTCO2e)

Washington PRS
Washington’s PRS has also changed dramatically from the 2021 IRP. The CCA has
introduced a cap-and-trade program with the ability to cover emissions with an allowance
or offset. Allowance and offset prices may drive a different PRS than the one illustrated
in Figure 6.22. The range of allowance prices for 2023 is $22 to $82 USD. The PRS shows
conventional natural gas and energy efficiency as the primary energy source options until
the end of the study horizon (2044), when synthetic methane is chosen. The darker blue
area in the chart is the CCA program cap and would not require any type of program
instruments. The lighter blue area represents natural gas as an energy source, requiring
an offset or an allowance as it is above the cap. Natural gas will continue to be procured
from the least cost supply basin as shown in Figure 6.23.

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Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-27

Figure 6.22: Washington Preferred Resource Strategy

Figure 6.23: Natural Gas Basin Least Cost - Washington

The specific resource selection by year is shown in Table 6.5. Avista does not expect a
significant reduction in traditional natural gas use with the CCA prices assumed in this
expected case. Chapter 7 identifies how reduction in traditional natural gas may occur
either by way of higher CCA prices or non-cost-effective electrification.

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)
Natural Gas - No Allowance Natural Gas With Allowance
Synthetic Methane DSM
0
5
10
15
20
25
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
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1
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4
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4
5
De
k
a
t
h
e
r
m
s

(
M
i
l
l
i
o
n
s
)
AECO (WA)Rockies (WA)Spokane (WA)
Stanfield (WA)Station 2 (WA)Sumas (WA)
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-28

Table 6.5: Average Daily Resource Quantities by Year – Washington

Year Energy
Efficiency
Natural
Gas
Synthetic
Methane
Allowances
DTh
Equivalent
Natural
Gas - No
allowance
Natural
Gas with
allowance
2023 404 60,537 - 6,807 53,730 6,807
2024 507 60,881 - 10,804 50,077 10,804
2025 558 64,507 136 18,075 46,432 18,075
2026 519 59,228 - 17,105 42,122 17,105
2027 563 62,859 - 24,688 38,171 24,688
2028 612 63,497 119 29,472 34,026 29,472
2029 685 59,521 3 29,412 30,109 29,412
2030 717 62,552 0 36,417 26,135 36,417
2031 723 61,364 - 36,236 25,128 36,236
2032 717 61,759 52 37,748 24,011 37,748
2033 686 62,066 141 39,023 23,043 39,023
2034 641 61,415 - 39,422 21,994 39,422
2035 585 63,193 3 42,210 20,983 42,210
2036 546 62,735 - 42,884 19,851 42,884
2037 496 60,887 5 42,055 18,833 42,055
2038 427 62,836 20 44,967 17,869 44,967
2039 372 65,626 157 48,772 16,854 48,772
2040 340 63,017 177 47,287 15,730 47,287
2041 300 61,895 20 47,151 14,744 47,151
2042 287 64,523 159 50,754 13,769 50,754
2043 154 62,775 14 50,559 12,217 50,559
2044 136 61,087 428 50,438 10,649 50,438
2045 129 54,741 6,313 45,678 9,063 45,678

Allowances and offsets will be considered interchangeably and compared to one another
with available options at the time of purchase. In the event Avista can obtain offsets at a
lower price than allowances, offsets will be purchased in place of allowances. The PRS
selects program instruments each year as shown in Figure 6.24 with bounds to address
the potential need for more or less allowances. Similar to CCIs in Oregon, the range of
allowance volumes beginning in 2040 becomes volatile as alternative resources become
cost effective in comparison to natural gas paired with an allowance.

Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-29

Figure 6.24: CCA Allowances/Offsets Quantity Needed (MTCO2e)

Monte Carlo Risk Analysis
Avista uses 500 Monte Carlo draws (23-year futures, 2023 – 2045) to measure the
statistical risk of varying elements such as price and demand based on the new resources
selected from the five stochastic simulations. Weather and price risk related to costs of
our PRS case are put through a Monte Carlo simulation based on the stochastic scenario
solve. The Monte Carlo simulation in PLEXOS® can vary index price and weather
simultaneously. This simulates the effects each have on the other. Monte Carlo solves
resources and demand need for each year based on least cost pricing.

Avista performed stochastic modeling for estimating probability distributions of potential
outcomes by allowing for random variation in natural and renewable gas prices,
Allowance prices, the occurrence of a national carbon tax applied to Idaho beginning in
2030, 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.

Annual system demand costs are summarized in Figure 6.25 and illustrate the cost
volatility across the system. Some costs such as CCIs for compliance with the CPP are
known, other than inflation, so there is little risk in the movement of costs from year to
year. The costs of allowances or offsets to comply with the CCA are not known and can
move between the floor and ceiling on an annual basis. Figures 6.25 through 6.28
illustrate the specific cost information based on jurisdiction.

-
200
400
600
800
1,000
1,200
20
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3
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C
O
2
e

(
T
h
o
u
s
a
n
d
s
)
1% - 99% Range
Average
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-30

Figure 6.25: System Annual Costs – 1,000 of $ (500 Draws)

Figure 6.26: Idaho Annual Costs – 1,000 of $ (500 Draws)

Annual Average 419,514$
Annual Min 190,979$
Annual Max 984,852$
Annual Median 412,159$
5th %250,079$
95th %630,039$
Std. Dev.123,398$
Annual Average 67,540$
Annual Min 20,193$
Annual Max 230,954$
Annual Median 61,613$
5th %38,310$
95th %118,428$
Std. Dev.25,367$
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-31

Figure 6.27: Oregon Annual Costs – 1,000 of $ (500 Draws)

Figure 6.28: Washington Annual Costs – 1,000 of $ (500 Draws)

Annual Average 182,757$
Annual Min 82,161$
Annual Max 401,274$
Annual Median 198,197$
5th %97,366$
95th %266,106$
Std. Dev.62,533$
Annual Average 169,217$
Annual Min 75,267$
Annual Max 451,515$
Annual Median 159,081$
5th %105,852$
95th %265,837$
Std. Dev.50,049$
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-32

Estimated Price Impacts
The estimated rate impacts are intended to give a commodity only estimate of impacts to
meet the energy demand and emissions goals. Specifically, these price estimates include
contracted, owned, or leased infrastructure resources, the energy and any fuel needed to
move the energy (if required). The price impacts by specific customer class, like low-
income residential customers in Washington, will differ from non-low-income customers.
These are just for illustrative purposes to general area and class. General and
administrative costs of providing energy, office support, and its infrastructure are not
included in these overall estimates. Figure 6.29 through Figure 6.32 illustrate price
impacts by generic class and jurisdiction.

Figure 6.29: Residential Price Impact ($ of therm)

Figure 6.30: Commercial Price Impact ($ per therm)

$-
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
$1.60
$1.80
$2.00
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Oregon
Washington
$-
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$0.80
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$1.40
$1.60
$1.80
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Oregon
Washington
Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-33

Figure 6.31: Industrial Price Impact ($ per therm)

Figure 6.32: Transport Price Impact ($ per therm)

$-
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
$1.60
$1.80
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Oregon
Washington
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Chapter 6: Preferred Resource Strategy

Avista Corp 2023 Natural Gas IRP 6-34

This Page Intentionally Left Blank

Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-1
7. Alternate Scenarios

Avista applied the Preferred Resource Strategy and Risk analysis in Chapter 6 to
alternate demand and supply resource scenarios to develop a range of alternate
portfolios. This modeling approach considered different underlying assumptions vetted
with the TAC members to develop a consensus about the number of cases to model.
These scenarios help in the understanding of the PRS results and to provide insight of
the costs and benefits with policy changes.

Alternate Demand Scenarios
As discussed in Chapter 2, Avista identified alternate scenarios for detailed analysis to
capture a range of possible outcomes over the planning horizon. The scenarios consider
different demand and price-influencing factors as shown in Table 7.1.

Table 7.1: 2023 IRP Scenarios

Deterministic – Portfolio Evaluation and Scenario Results
A deterministic evaluation was used to consider alternative scenarios. 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 Scenario by creating high and low boundaries for
customer count, weather, and pricing. Each portfolio runs through PLEXOS® 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 least cost results.
2023 IRP Scenarios
Natural
Gas
Prices
DSM
Potential CCA Customer
Growth
Electrification
Conversion
Costs
Renewable
Prices
Renewable
Supply
Pipeline
Outages
Carbon
Intensity
Natural Gas
Carbon
Intensity
Renewables
Cost of
Carbon Weather UPC CPP
PRS Expected Expected
PRS - Low Prices Low Low
PRS - High Prices High High
PRS - Allowance Price
Ceiling
Ceiling Price
(Allowances)
Electrification -
Expected
Conversion Costs
Electrification - High
Conversion Costs High
Electrification - Low
Conversion Costs Low
High Customer Case High
Limited RNG
Availability High Low
Interrupted Supply
50%
Capacity
Station 2,
Sumas,
and Rockies
Carbon Intensity
128.27 lbs.
per
Dekatherm
Carbon
Intensity
Social Cost of Carbon Social Cost of
Carbon @ 2.5%
Average Case 20 Year
Average
Hybrid Case Climate
Change
Space Heat
Demand Only for
Hybrid
Customers
0 lbs.
per
Dekatherm Carbon Tax
Beginning 2030
Idaho Only
Expected Expected
None 117 lbs.
per
Dekatherm
None
117 lbs.
per
Dekatherm
Climate
Change
5-Year UPC - OR
3-Year UPC - ID
3-Year UPC WA
Space Heat
Demand Only for
New Residential
+
New Commercial
Customers in
Washington
Emission
Targets
+
CCI
PricesExpectedExpectedExpected
Price
(Allowances)
Electrification
Expected
Price
(Allowances)Expected
Expected
Expected Expected
0 lbs.
per
Dekatherm
Carbon Tax
Beginning 2030
Idaho Only
ExpectedExpected
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-2
Demand
Demand profiles, for firm customers and net of DSM measures, over the planning horizon
for each of the scenarios shown in Figure 7.1. illustrate the demand risks from the
alternate scenarios. The demand for our High Customer Case shows the greatest
expected system demand with the Electrification Cases showing the lowest expected
demand. As discussed in previous chapters, demand is the greatest risk in this IRP and
has fundamentally changed due to building codes and climate programs. The PRS, and
associated scenarios, all show an increasing demand through the study horizon while the
Electrification scenarios assume a steady conversion of natural gas customers to the
electric grid. Further analysis will be necessary to carefully consider impacts to future
demand expectations and resources to meet those needs.

Figure 7.1: Demand by Scenario

PRS Scenarios
The PRS Alternative Scenarios measure the same basic assumptions as the PRS, but
study different cost implications for modeled resources options. These scenarios consider
lower and higher natural gas prices and the ceiling price for the CCA to help determine a
crossover point for different resources. The costs for these resources can vary for a
myriad of reasons such as supply issues, inflation, or policy. Individual descriptions are
provided below by scenario. Figure 7.2 illustrates the alternative PRS scenarios as
compared to the PRS costs.

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10,000
20,000
30,000
40,000
50,000
60,000
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k
a
t
h
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r
m
s

(
T
h
o
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a
n
d
s
)
Hybrid Case Average Case
PRS - Low Prices PRS - High Prices
Electrification Cases High Customer Case
PRS + All Other Cases
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-3
Preferred Resource Strategy (PRS)
Included in Chapter 7 to illustrate the different outcomes for prices and demand based on
different scenarios. A full description of the PRS can be found in Chapter 6.

Preferred Resource Strategy – Low Prices
Considers both lower price expectations by resource, as discussed in Chapter 4 and a
resulting lower avoided cost curve and DSM potential, as described in Chapter 3. This
will help determine a least cost supply and demand side resource selection assuming
natural gas prices are lower than our expected price curve.

Preferred Resource Strategy – High Prices
Considers a higher resource price combined with a higher DSM potential. A new set of
supply and demand side resources and compliance instruments for the CCA and CPP
are selected to maintain emissions compliance.

Preferred Resource Strategy – Allowance Price Ceiling
A scenario to consider a ceiling price in the CCA program in Washington State. The
auction process and quantity of allowances available and an unknown amount of demand
for these instruments creates a risk to the IRP considerations if the allowance price is
higher than expected. This scenario considers a ceiling allowance price and resource
selection alternatives to acquire a set of least cost and risk portfolio.

Annual system costs for alterative future scenarios compared to the PRS are illustrated
in Figure 7.2.

Figure 7.2: PRS Scenarios - Annual System Costs

$-
$100,000
$200,000
$300,000
$400,000
$500,000
$600,000
$700,000
$800,000
$900,000
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n
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y
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t
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m

C
o
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t

(
T
h
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u
s
a
n
d
s
)
PRS
PRS - Allowance Price Ceiling
PRS - High Prices
PRS - Low Prices
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-4
In Table 7.2, the portfolio selections for these alternative scenarios can be compared to
the PRS where energy resources are in thousands of dekatherms and compliance
instruments are in metric tons of carbon dioxide equivalent (MTCO2e). Quantities are
similar across the three PRS scenario alternatives other than the quantity of natural gas
selected.

Table 7.2: PRS Scenarios - Portfolio Selections

Scenario Category 2025 2035 2045
PRS Synthetic Methane (,000s of Dth) 93 146 5,191
PRS OR - Renewables (,000s of Dth) 2,000 7,295 8,973
PRS Natural Gas (,000s of Dth) 45,485 42,403 37,022
PRS CCI (MTCO2e) 16,758 70,337 -
PRS Allowances (MTCO2e) 283,273 793,898 884,819
PRS - Allowance Price Ceiling Synthetic Methane (,000s of Dth) 93 146 24,009
PRS - Allowance Price Ceiling OR - Renewables (,000s of Dth) 1,927 7,210 8,560
PRS - Allowance Price Ceiling WA - Renewables (,000s of Dth) 29 24 555
PRS - Allowance Price Ceiling Natural Gas (,000s of Dth) 45,685 42,676 18,645
PRS - Allowance Price Ceiling CCI (MTCO2e) 16,758 70,337 -
PRS - Allowance Price Ceiling Allowances (MTCO2e) 283,273 793,898 -
PRS - High Prices Synthetic Methane (,000s of Dth) 91 145 6,913
PRS - High Prices OR - Renewables (,000s of Dth) 2,621 7,225 8,966
PRS - High Prices WA - Renewables (,000s of Dth) - - -
PRS - High Prices Natural Gas (,000s of Dth) 45,094 42,533 35,258
PRS - High Prices CCI (MTCO2e) - 70,337 -
PRS - High Prices Allowances (MTCO2e) 282,841 792,175 860,762
PRS - Low Prices Synthetic Methane (,000s of Dth) 94 146 5,175
PRS - Low Prices OR - Renewables (,000s of Dth) 1,745 7,288 8,981
PRS - Low Prices Natural Gas (,000s of Dth) 45,907 42,047 36,777
PRS - Low Prices CCI (MTCO2e) 38,441 70,337 -
PRS - Low Prices Allowances (MTCO2e) 283,889 794,288 884,819

Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-5
Electrification Scenarios
Avista uses four scenarios to identify impacts to the natural gas and power system if
space and water heating is electrified in the Oregon and Washington service areas,
specifically for the residential and commercial customers. Industrial customers are not
considered as each process would require an individual analysis to determine if
electrification is possible or if an alternative fuel would be a better option.

A loss of demand is expected on the natural gas system in each scenario. These
scenarios also estimate cost impacts to convert and replace the energy moved to the
power grid combined with remaining costs for program compliance and energy on the
natural gas system. Chapter 2 explains methodology to remove demand from the natural
gas system and Chapter 3 explains methodology for conversion costs and power costs.

Electrification – Expected Conversion Cost
This scenario considers a loss of customers in Oregon and Washington at roughly 2%
annually. All remaining assumptions remain consistent with the PRS scenario. Additional
electrification is available to the model and compared to other resources available as a
least cost option.

Electrification – Low Conversion Cost
An alternate scenario to our Electrification – Expected Conversion Cost, to consider the
impacts of lower-than-expected conversion costs, 50% of expected costs, and the
potential resources selected. The model is forced to reduce at 2% per year in Oregon and
Washington. Additional electrification is available to the model in a least cost option.

Electrification – High Conversion Cost
An alternate scenario to our Electrification – Expected Conversion Cost, to consider the
impacts of higher-than-expected conversion costs, 150% of expected costs, and the
potential resources selected. The model is forced to reduce at 2% per year in Oregon and
Washington. Additional electrification is available to the model in a least cost option.

Hybrid Case
The Hybrid Case considers the use of the natural gas system for peak heating needs with
non-peak electrified for heat sensitive usage below 40 degrees Fahrenheit. This scenario
assumes the conversion to a hybrid system utilizing the same decreasing customer
trajectory as the electrification scenarios and only for Oregon and Washington. Rather
than a total loss of these customers, a customer would remain on the natural gas system
for use with back up heating. Like the Electrification scenarios, after converting estimated
demand from natural gas to electricity from Oregon and Washington with efficiencies
estimated in Chapter 3, the remaining price impact is added to account for total costs of
the electric and natural gas systems. All other assumptions remain consistent to the PRS.
In Figure 7.3, the annual levelized costs by major end source are provided. These major
end sources include costs from the natural gas system, conversion costs for incremental
customers, and the cost of electricity for these converted end sources.
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-6
Figure 7.3: Annual Electrification Levelized Costs by Source

Portfolio selections by scenario and category are shown in Table 7.3. Energy is in
thousands of dekatherms and allowances and CCIs are in Metric Tons of Carbon Dioxide
equivalent (MTCO2e).

(133.87)(133.87)(133.87)
(34.70)
(299.26)
(81.71)(40.85)
(81.71)
(306.22)
(306.22)
(306.73)
(327.50)
($800)
($700)
($600)
($500)
($400)
($300)
($200)
($100)
$0
An
n
u
a
l

L
e
v
e
l
i
z
e
d

C
o
s
t

(
M
i
l
l
i
o
n
s
)
High Expected Low Hybrid
Electricity Cost Conversion Cost Natural Gas Cost
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-7
Table 7.3: Electrification Scenarios - Portfolio Selections

Scenario Category 2025 2035 2045
Elec. - Expected Conversion
Costs Synthetic Methane (,000s of Dth) 81 42 2,057
Elec. - Expected Conversion
Costs OR - Renewables (,000s of Dth) 1,694 4,044 5,975
Elec. - Expected Conversion
Costs Natural Gas (,000s of Dth) 45,195 37,759 29,218
Elec. - Expected Conversion
Costs CCI (MTCO2e) 24,894 70,337 -
Elec. - Expected Conversion
Costs Allowances (MTCO2e) 260,407 538,955 555,307
Elec. - High Conversion Costs Synthetic Methane (,000s of Dth) 81 42 2,057
Elec. - High Conversion Costs OR - Renewables (,000s of Dth) 1,694 4,044 5,975
Elec. - High Conversion Costs Natural Gas (,000s of Dth) 45,188 37,759 29,225
Elec. - High Conversion Costs CCI (MTCO2e) 24,506 70,337 -
Elec. - High Conversion Costs Allowances (MTCO2e) 260,407 538,955 555,705
Elec. - Low Conversion Costs Synthetic Methane (,000s of Dth) 85 42 1,434
Elec. - Low Conversion Costs OR - Electrification (,000s of Dth) 934 934 932
Elec. - Low Conversion Costs OR - Renewables (,000s of Dth) 1,467 3,774 5,667
Elec. - Low Conversion Costs Natural Gas (,000s of Dth) 44,711 37,453 29,151
Elec. - Low Conversion Costs CCI (MTCO2e) 99 53,709 -
Elec. - Low Conversion Costs Allowances (MTCO2e) 260,407 538,955 551,783
Hybrid Case Synthetic Methane (,000s of Dth) 93 140 2,820
Hybrid Case OR - Renewables (,000s of Dth) 1,694 4,570 6,459
Hybrid Case Natural Gas (,000s of Dth) 45,541 40,831 34,820
Hybrid Case CCI (MTCO2e) 24,506 70,337 -
Hybrid Case Allowances (MTCO2e) 279,381 705,858 825,407

Electrification Selected as a Resource
Electrification as a selected resource occurred in two scenarios as illustrated in Figure
7.4. The first in the Limited RNG Availability with the second in our Electrification – Low
Conversion Costs case, both selections are for Avista’s Oregon territory. Limited RNG
creates a resource issue to meet emissions goals and is the only scenario that selects
electrification based on our estimated costs per Dth as described in Chapter 3. The model
selected electrification in the first available year, removing 1.5 million dekatherms of
demand per year for the study horizon. No additional electrification was selected after
2023 as the model is given a choice to add additional electrification to reduce load as a
least cost, meaning no other electrification was least cost past the first year. The
Electrification – Low Conversion Costs case shows the potential for electrification as a
demand side resource. The Medford Residential customers select space heat
electrification as a resource removing 934,400 dekatherms of demand annually beginning
in 2023. As in the Limited RNG Availability Case, no additional electrification is selected
after 2023 as a least cost option. These results show a potential to alter demand for
electric end uses if conversion costs are lower than expected through grants, tax incentive
or discounts.
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-8
Figure 7.4: Electrification as a Demand-Side Resource by Scenario and State

Supply Scenarios
The supply scenarios help to illustrate implications of physical impacts to the system,
impacts to program compliance or resource availability. Outages and expected volume
availability of resources such as RNG pose a risk to serving demand and meeting
emissions compliance. These scenarios are Limited RNG availability, Interrupted supply
and Carbon Intensity and help demonstrate potential pathways for program compliance
with resource risk.

Carbon Intensity
Carbon Intensity is considered in the event the Washington CCA or Oregon CPP alter
program methodologies or combine with the California Cap and Trade program. The only
change from the PRS is the carbon intensity of RNG resources. Cost Impact and RNG
source and quantity selected is a primary measure of this scenario. This scenario also
considers carbon intensity in the natural gas fuel from upstream emissions at 128.27
pounds per dekatherm. In the California cap and trade program anaerobic sources are
valued by carbon intensity meaning a dairy project may be considered as the value of
reduced methane from the capture of these sources brings the cost down by over 400
percent (Chapter 4, Table 4.2 Carbon Intensity).

Limited RNG Availability
The availability of RNG in sufficient quantities to meet CCA and CPP emissions targets
is measured in this scenario. This scenario constrains the expected RNG volumes to 50%
with high RNG prices as discussed in Chapter 4.

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Electrification - Low Conversion Costs - Oregon
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-9
Interrupted Supply
The Interruptible Supply case considers constraints of 50% availability at major supply
points on the Northwest Pipeline system to measure risk of unserved demand. This
scenario looks solve a least cost resource selection due to the risk of pipeline outages,
equipment failure such as compressors or pipeline rupture as experienced in 2018 with
the Enbridge pipeline. All other factors are consistent with PRS.

Figure 7.5 illustrates the annual system cost in comparison to the PRS. The Carbon
Intensity scenario shows a lower system cost in the outer years but is not currently within
CCA or CPP program rules and is included as an estimate of rule changes.

Figure 7.5: Supply Scenarios vs PRS - Annual System Costs

The portfolio selections for these Supply Scenarios include least cost resources provided
to the model based on Carbon Intensity, Interrupted supply and Limited RNG as illustrated
by Scenario and Category in Table 7.4. Energy is in thousands of dekatherms and
allowances and CCIs are in MTCO2e.

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Carbon Intensity
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-10
Table 7.4: Supply Scenarios – Portfolio Selection

Scenario Category 2025 2035 2045
Carbon Intensity Synthetic Methane (,000s of Dth) 98 153 5,477
Carbon Intensity OR – Renewables (,000s of Dth) 927 2,212 4,157
Carbon Intensity WA – Renewables (,000s of Dth) - - 44
Carbon Intensity Natural Gas (,000s of Dth) 47,126 47,799 42,385
Carbon Intensity CCI (MTCO2e) - 624 -
Carbon Intensity Allowances (MTCO2e) 395,722 907,878 884,819
Interrupted Supply Synthetic Methane (,000s of Dth) 120 181 5,137
Interrupted Supply OR - Renewables (,000s of Dth) 1,993 7,232 8,982
Interrupted Supply Natural Gas (,000s of Dth) 45,653 42,468 36,944
Interrupted Supply CCI (MTCO2e) 17,146 70,337 -
Interrupted Supply Allowances (MTCO2e) 283,273 793,898 884,819
Limited RNG Availability Synthetic Methane (,000s of Dth) 98 2,552 9,075
Limited RNG Availability OR - Electrification (,000s of Dth) 1,545 1,561 1,562
Limited RNG Availability OR - Renewables (,000s of Dth) 774 3,368 3,526
Limited RNG Availability Natural Gas (,000s of Dth) 45,479 42,642 37,023
Limited RNG Availability CCI (MTCO2e) 16,758 70,337 -
Limited RNG Availability Allowances (MTCO2e) 283,273 793,898 884,819

Other Scenarios
The Average Case is a key scenario to show peak demand versus the demand used to
plan for an average use scenario. It considers average 20-year historic weather without
climate futures to quantify the impacts of future temperatures and resource needs. This
Average Case scenario uses historic temperatures from its planning areas to estimate
demand based on weather and use per customer. The High Customer Case is
exceedingly unlikely due to policy in Oregon and Washington but is also important as a
perspective to understand costs of resources and environmental compliance given a
higher than expected demand. Our Idaho territory may have a greater potential for this
risk given the above system average growth combined with no current policy restricting
the use of natural gas. Finally, the Social Cost of Carbon is considered as a method to
value system costs using impacts as estimated through the Social Cost of Carbon at
2.5%.

High Customer Growth
Measuring risk includes a higher-than-expected case for customer growth in our natural
gas territories. While Oregon and Washington have policy and programs making this
unlikely, Idaho is experiencing strong growth as discussed in Chapter 2.

Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-11
Social Cost of Carbon
Assumes PRS inputs with a SCGHG at the 2.5% discount rate for all resources to
compare in supply side resource selection. This cost overrides the costs of compliance in
the CCA and CPP programs.

Average Case
The Average Case uses only the average daily weather for the past 20 years as compared
to the PRS. All other assumptions are used from the PRS, excluding a peak day. This
helps to show average demand as seen historically to compare to cases where demand
is impacted from resources, weather forecasts, or peak day.

A cost comparison is provided in Figure 7.6 and compares these “Other” scenarios to the
PRS annual system costs. In Table 7.5, selected resources by portfolio are included by
Scenario and Category.

Figure 7.6: Other Scenarios vs PRS - Annual System Costs

A portfolio selection is provided in Table 7.5 for these other scenarios. Energy is in
thousands of dekatherms and allowances and CCIs are in MTCO2e. Renewable energy
increases drastically in the Social Cost of Carbon case as higher costs lead to greater
demands for carbon free fuels. The model must take the same quantity of RNG once
chosen for the remainder of the study. If, for example, 10 dekatherms were chosen in
2025, the model must take this same amount of volume through the end of the study. This
method creates a more realistic consideration of obtaining RNG. Due to additional uptake
in RNG, CCIs have less demand and is replaced by additional RNG.

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High Customer Case
Average Case
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-12
Table 7.5: Other Scenarios – Portfolio Selection

Scenario Category 2025 2035 2045
Average Case Synthetic Methane (,000s of Dth) - - 8,487
Average Case OR - Renewables (,000s of Dth) 1,686 6,638 8,313
Average Case WA - Renewables (,000s of Dth) 7 2 204
Average Case Natural Gas (,000s of Dth) 45,249 43,506 36,140
Average Case CCI (MTCO2e) 18,631 70,337 -
Average Case Allowances (MTCO2e) 271,571 822,730 884,819
High Customer Case Synthetic Methane (,000s of Dth) 99 181 6,901
High Customer Case OR - Renewables (,000s of Dth) 2,139 7,672 9,514
High Customer Case Natural Gas (,000s of Dth) 45,818 43,582 38,436
High Customer Case CCI (MTCO2e) 16,758 70,337 -
High Customer Case Allowances (MTCO2e) 290,676 816,701 884,819
Social Cost of Carbon Synthetic Methane (,000s of Dth) 87 146 42,344
Social Cost of Carbon OR - Renewables (,000s of Dth) 3,482 7,299 9,028
Social Cost of Carbon WA - Renewables (,000s of Dth) - - 497
Social Cost of Carbon Natural Gas (,000s of Dth) 45,069 42,261 -
Social Cost of Carbon CCI (MTCO2e) - 70,337 -
Social Cost of Carbon Allowances (MTCO2e) 283,273 793,898 -

Washington Climate Commitment Act Allowances
The Carbon Intensity scenario has the highest requirement for allowances through 2030,
though the lines generally converge in the 2030 timeframe with similar quantity estimates.
PRS is included to show the variation of resources needed to help reduce emissions or
meet emissions targets. In the Social Cost of Carbon scenario, higher costs lead to a
higher RNG demand by 2025 reducing the need for allowances. All other scenarios are
generally within the blue area depicting the PRS results. The Hybrid Case has the lowest
quantity of allowances due to the reduced demand and energy supplied by the natural
gas system. By 2042 the PRS – Allowance Price Ceiling case and 2043 the Social Cost
of Carbon case both show allowance requirements fall to zero as synthetic methane
becomes the least cost resource for the CCA. The variability of allowances is illustrated
in Figure 7.7.

Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-13
Figure 7.7: Allowance Demand by Scenario – Washington CCA

Oregon Community Climate Investments
Community Climate Investments show a greater range of required quantities for
compliance. In Figure 7.8, the maximum amount of CCIs available beginning in 2023 can
be found in the gray area. The steps are based on the quantity of CCIs available in each
timeframe as allowed per the rules (Chapter 5). The PRS acquires near the cap by 2026
with many scenarios following a similar pathway. The Electrification scenarios generally
require fewer instruments in the near term due to a loss of demand on the natural gas
system which removes the larger CCIs needed. The Social Cost of Carbon scenario
acquires a higher level of renewable fuels and removes the need for more CCIs to pair
with natural gas. Finally, the most interesting result is from our Carbon Intensity scenario.
The demand for CCIs does not generally come around until 2040 and only for a few years
until future renewable resources are brought onto the system.

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Electrification Cases Hybrid Case
Social Cost of Carbon Interrupted Supply
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-14
Figure 7.8: CCI Demand by Scenario – Oregon CPP

Natural Gas Use
The demand for natural gas decreases across all studied scenarios in this IRP. The
scenario with the greatest decline is the Social Cost of Carbon case where by 2045 it
eliminates natural gas from its resource selection. This case is followed by the PRS –
Allowance Price Ceiling with only 41% of energy being filled by natural gas. The overall
decrease across these fourteen scenarios is an average of 31% by 2045 as compared to
2025. Figure 7.9 illustrates the use of natural gas across all scenarios in 2025, 2035 and
2045. The future of natural gas is facing a fundamental change at Avista, the Pacific
Northwest and nations in the climate pledge with the goal to reduce global emissions.1

1 https://www.ipcc.ch/about/
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Electrification - Low Conversion Costs
Hybrid Case
Social Cost of Carbon
Interrupted Supply
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-15
Figure 7.9: Natural Gas Supply

Synthetic Methane
Synthetic methane has been chosen as a resource across all scenarios as illustrated in
Figure 7.10. Reducing emissions is key to the selection of synthetic methane with cost
expectations around carbon capture and green hydrogen reducing over time as discussed
in Chapter 4, this energy source may prove to be an important fuel in emissions
compliance programs. Further studies and lifecycle analysis will be necessary if selected
as a resource or through a request for procurement (RFP). Important pieces to consider
include waste from the process to create hydrogen or carbon capture, permitting for a
water supply in the electrolysis process and waste.

Figure 7.10: Annual Synthetic Methane Volumes by 2045

2025 2035 2045
Min 44.71 37.45 -
Avg 45.51 41.84 31.50
Max 47.13 47.80 42.39
PRS 45.48 42.40 37.02
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PRS
Carbon Intensity
High Customer Case
PRS - High Prices
Average Case
Limited RNG Availability
PRS - Allowance Price Ceiling
Social Cost of Carbon
Dekatherms (Millions)
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-16
Renewable Natural Gas
Renewable Natural Gas is considered a necessary energy and emissions reduction tool
for the CCA and CPP. While costs vary by project, location, and size, RNG is necessary
to meet initial needs of emissions reduction until other resource options can be further
matured and advanced. Idaho does not select any RNG under any scenario even when
considering a national carbon tax as discussed in in Chapter 5. Oregon, under the CPP,
chooses RNG consistently across all scenarios as illustrated in Figure 7.11. The variability
occurs with different costs and system customers. RNG is also considered an important
fuel to consider for the replacement of natural gas in industrial processes as these
processes can be more difficult to electrify.

Figure 7.11: Oregon RNG Volumes Across Scenarios
Currently, Washington is considering linkage to the California cap and trade program. In
the event program rules change under the CCA or CPP, RNG may provide for the ability
to reduced emissions program costs with the use of higher carbon intensive RNG
sources. With the expected price of allowances relatively low in the first years of the CCA,
RNG has a limited uptake across most scenarios. As previously discussed, if cost
assumptions due to inflation and its impact on allowance prices, allowance availability,
changes to compliance resources may change. Figure 7.12 illustrates all studied
scenarios in this IRP where RNG was chosen.

2025 2035 2045
Min 0.77 2.21 3.53
Avg 1.85 5.71 7.36
Max 3.48 7.67 9.51
PRS 2.00 7.30 8.97
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-17
Figure 7.12: Washington RNG Volumes Across Scenarios

Emissions
Emissions compliance to the CCA and CPP have been met in all scenarios studied in the
2023 IRP. These scenarios consider a sizeable range of future outcomes including the
loss of customers from policy, regulation, and customer choice. The resultant outcomes
depict a varying level of emissions based on selected resources and demand reduction.
When considering the primary reasons for reducing emissions, the cap in each program
creates a requirement to meet stated targets. The Carbon Intensity scenario highlights
additional carbon in Idaho from upstream emissions, while the other scenarios mostly
follow a similar trajectory. This is illustrated in Figure 7.13 and only vary slightly based on
the number of customers on the system with growth occurring in Idaho in all scenarios.

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Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-18
Figure 7.13: System Emissions by Scenario by 2030

Cost Comparison
When we consider costs of these scenarios, there are two with a cost lower than the PRS.
The first is the Average Case and the second is PRS – Low Prices. The Average Case is
like the PRS with two primary differences, price assumptions for energy and weather
futures. Recall the Average Case does not include peak weather and should be used as
a reference to all scenarios considered. The overall lower demand creates less energy
supplied and lower emissions to meet compliance in compliance in the CCA and CPP.
The PRS – Low Prices is measuring the same demand as the PRS with just lower costs
than expected. Electrification costs include incremental conversion costs of customers
and energy costs from the power grid as discussed in Chapter 3. These electrification
costs are included in all three Electrification scenarios and the Hybrid Case. These
levelized costs consider twenty years as CPA estimates are not available from the ETO
past this mark as illustrated in Figure 7.14.

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Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-19
Figure 7.14: PRS Alternative Scenario Cost Comparison
Annual Levelized Costs (2023 – 2042)

The estimated price impact by scenario by generic class and area are included in Figure
7.15 to 7.19.

Figure 7.15: Residential Customer Price Impact ($ per dekatherm)

PR
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Average Case 3.76 5.54 8.75 10.06 25.28 14.37 6.28 7.06 14.66
Carbon Intensity 4.60 6.07 9.09 7.50 10.84 14.41 7.54 7.89 14.68
Electrification - Expected Conversion Costs 4.57 5.50 8.77 10.19 23.94 12.98 7.03 6.89 9.80
Electrification - High Conversion Costs 4.57 5.50 8.77 10.19 23.94 12.98 7.03 6.89 9.80
Electrification - Low Conversion Costs 4.57 5.50 8.78 5.06 12.47 13.22 7.03 6.89 9.81
High Customer Case 4.61 6.21 8.86 10.18 24.77 14.62 7.32 7.97 14.63
Hybrid Case 4.60 5.88 9.02 10.41 23.87 14.43 7.45 7.58 10.31
Interrupted Supply 4.60 6.20 8.96 10.17 24.72 14.58 7.31 7.96 14.40
Limited RNG Availability 4.60 5.84 8.94 9.15 30.14 14.74 7.32 7.59 14.39
PRS 4.60 5.95 8.94 10.19 24.82 14.59 7.31 7.64 14.39
PRS - Allowance Price Ceiling 4.45 5.85 8.70 10.17 24.94 14.61 9.72 14.77 14.81
PRS - High Prices 6.32 8.65 13.27 9.77 24.93 14.51 9.02 10.33 14.50
PRS - Low Prices 4.06 4.82 7.19 9.69 24.74 14.61 6.78 6.52 14.37
Social Cost of Carbon 9.93 12.17 14.79 9.42 24.03 14.34 12.62 15.24 14.82
Idaho Residential Oregon Residential Washington Residential
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-20
Figure 7.16: Commercial Customer Price Impact ($ per dekatherm)

Figure 7.17: Industrial Customer Price Impact ($ per dekatherm)

Figure 7.18: Transport Only Customer Price Impact ($ per dekatherm)

2025 2035 2045 2025 2035 2045 2025 2035 2045
Average Case 3.72 5.49 8.69 10.02 25.11 14.18 6.27 7.05 14.64
Carbon Intensity 4.49 5.98 9.02 7.44 10.80 14.35 7.51 7.87 14.66
Electrification - Expected Conversion Costs 4.46 5.44 8.69 10.16 23.91 12.93 6.98 6.86 9.76
Electrification - High Conversion Costs 4.46 5.44 8.69 10.16 23.91 12.93 6.98 6.86 9.76
Electrification - Low Conversion Costs 4.46 5.44 8.71 5.03 12.45 13.19 6.98 6.86 9.77
High Customer Case 4.50 6.10 8.78 10.13 24.59 14.55 7.30 7.96 14.61
Hybrid Case 4.49 5.79 8.93 10.40 23.85 14.33 7.38 7.56 10.29
Interrupted Supply 4.49 6.09 8.87 10.11 24.57 14.48 7.29 7.94 14.38
Limited RNG Availability 4.49 5.69 8.85 9.10 29.65 14.58 7.29 7.55 14.37
PRS 4.49 5.86 8.86 10.13 24.66 14.49 7.29 7.63 14.37
PRS - Allowance Price Ceiling 4.36 5.77 8.63 10.11 24.81 14.52 9.70 14.75 14.81
PRS - High Prices 6.21 8.56 13.16 9.72 24.80 14.39 9.00 10.31 14.47
PRS - Low Prices 3.95 4.73 7.11 9.64 24.58 14.52 6.75 6.50 14.35
Social Cost of Carbon 9.83 12.10 14.77 9.36 23.84 14.14 12.60 15.22 14.81
Washington CommercialIdaho Commercial Oregon Commercial
2025 2035 2045 2025 2035 2045 2025 2035 2045
Average Case 3.62 5.38 8.55 9.83 24.23 13.24 6.06 6.76 14.32
Carbon Intensity 4.09 5.72 8.88 7.11 10.58 14.06 6.84 7.28 14.33
Electrification - Expected Conversion Costs 4.07 5.29 8.53 9.81 23.79 12.56 6.59 6.70 9.57
Electrification - High Conversion Costs 4.07 5.29 8.53 9.81 23.79 12.56 6.59 6.70 9.57
Electrification - Low Conversion Costs 4.07 5.29 8.55 4.67 12.31 12.52 6.59 6.70 9.59
High Customer Case 4.09 5.77 8.62 9.81 23.89 14.24 6.61 7.22 14.23
Hybrid Case 4.09 5.52 8.72 9.81 23.56 12.76 6.61 6.96 9.76
Interrupted Supply 4.09 5.77 8.69 9.79 23.85 14.03 6.61 7.22 13.94
Limited RNG Availability 4.09 5.32 8.66 9.01 29.69 14.55 6.62 6.77 13.91
PRS 4.09 5.59 8.68 9.81 23.91 14.04 6.61 7.02 13.93
PRS - Allowance Price Ceiling 4.01 5.55 8.49 9.81 24.22 14.11 9.10 14.23 14.71
PRS - High Prices 5.83 8.29 12.96 9.40 24.16 13.82 8.34 9.72 13.98
PRS - Low Prices 3.55 4.45 6.93 9.31 23.84 14.11 6.07 5.89 13.91
Social Cost of Carbon 9.47 11.88 14.72 9.09 22.93 13.20 11.98 14.72 14.73
Idaho Industrial Oregon Industrial Washington Industrial
2025 2035 2045 2025 2035 2045
Average Case 9.56 24.93 14.21 5.85 6.30 13.97
Carbon Intensity 3.39 12.77 14.11 6.08 6.57 13.98
Electrification - Expected Conversion Costs 9.56 23.51 14.62 5.85 6.30 9.20
Electrification - High Conversion Costs 9.56 23.51 14.62 5.85 6.30 9.20
Electrification - Low Conversion Costs 9.56 12.17 14.21 5.85 6.30 9.23
High Customer Case 9.56 24.42 14.21 5.85 6.30 13.80
Hybrid Case 9.56 23.27 14.22 5.85 6.30 9.23
Interrupted Supply 9.56 24.26 14.21 5.85 6.30 13.44
Limited RNG Availability 9.56 29.76 14.65 5.85 5.95 13.41
PRS 9.56 24.42 14.21 5.85 6.30 13.44
PRS - Allowance Price Ceiling 9.56 24.42 14.61 8.44 13.56 14.67
PRS - High Prices 5.11 6.14 14.07 7.56 8.97 13.47
PRS - Low Prices 9.02 24.37 14.24 5.31 5.17 13.44
Social Cost of Carbon 8.74 23.56 14.68 11.19 13.93 14.69
Oregon Transport Washington Transport
Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-21
Regulatory Requirements
IRP regulatory requirements in Idaho, Oregon, and Washington call for several key
components. The completed plan must demonstrate that the IRP:
• Examines a range of demand forecasts.
• Examines feasible means of meeting demand with both supply-side and demand-
side resources.
• Treats supply-side and demand-side resources equally.
• Describes the long-term plan for meeting expected demand growth.
• Describes the plan for resource acquisitions between planning cycles.
• Takes planning uncertainties into consideration.
• Involves the public in the planning process.

Avista addressed the applicable requirements throughout this document. Appendix 1.2 –
IRP Guideline Compliance Summaries lists the specific requirements and guidelines of
each jurisdiction and describes Avista’s compliance.

The IRP is also required to consider risks and uncertainties throughout the planning and
analytical processes. Avista’s approach in addressing this requirement was to identify
factors that could cause significant deviation from the expected outcomes in planning
conclusions. From this, Avista created a total of fourteen demand scenario alternatives,
which incorporated different customer growth, resource availability, use-per-customer,
weather, and price assumptions.

Avista analyzed peak day weather planning standard, performing sensitivity on HDDs and
modeling an alternate weather-planning standard using the coldest day in 20 years.
Stochastic analysis using Monte Carlo simulations in PLEXOS® supplemented this
analysis. Avista also used simulations from PLEXOS® to analyze price uncertainty and
the effect on total portfolio cost.

Avista examined risk factors and uncertainties that could affect expectations and
assumptions with respect to DSM programs and supply-side scenarios. From this, Avista
assessed the expected available supply-side resources and potential conservation
savings for evaluation.

The investigation, identification, and assessment of risks and uncertainties in our IRP
process should reasonably mitigate surprise outcomes.

Chapter 7: Alternate Scenarios
Avista Corp 2023 Natural Gas IRP 7-22

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Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-1

8. Distribution Planning

Avista’s IRP evaluates the safe, economical, and reliable full-path delivery of natural gas
from basin to the customer meter. Securing adequate natural gas supply and ensuring
sufficient pipeline transportation capacity to Avista’s city gates become secondary issues
if distribution system growth behind the city gates increases faster than expected and the
system becomes severely constrained. Important parts of the distribution planning
process include forecasting local demand growth, determining potential distribution
system constraints, analyzing possible solutions and estimating costs for eliminating
constraints.

Analyzing resource needs to this point has focused on ensuring adequate capacity to the
city gates, especially during a peak event. Distribution planning focuses on determining if
there will be adequate pressure during a peak hour. Despite this altered perspective,
distribution planning shares many of the same goals, objectives, risks, and solutions as
integrated resource planning.

Avista’s natural gas distribution system consists of approximately 3,300 miles of
distribution main and service pipelines in Idaho, 3,700 miles in Oregon and 5,800 miles
in Washington; as well as numerous regulator stations, service distribution lines,
monitoring and metering devices, and other equipment. Currently, there are no storage
facilities or compression systems within Avista’s distribution system. Distribution network
pipelines and regulating stations operate and maintain system pressure solely from the
pressure provided by the interstate transportation pipelines.

Distribution System Planning
Avista conducts two primary types of evaluations in its distribution system planning
efforts: capacity requirements and integrity assessments.

Capacity requirements include distribution system reinforcements and expansions.
Reinforcements are upgrades to existing infrastructure or new system additions, which
increase system capacity, reliability, and safety. Expansions are new system additions to
accommodate new demand. Collectively, these reinforcements and expansions are
distribution enhancements.

Ongoing evaluations of each distribution network in the five primary service territories
identify strategies for addressing local distribution requirements resulting from customer
growth. Customer growth assessments are made based on factors including IRP demand
forecasts, monitoring gate station flows and other system metering, new service requests,
field personnel discussion, and inquiries from major developers.

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
Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-2

system integrity upgrades coincides with growth-related expansion requirements. These
planning efforts provide a long-term planning and strategy outlook and integrate into the
capital planning and budgeting process, which incorporates planning for other types of
distribution capital expenditures and infrastructure upgrades.

Gas Engineering planning models are also compared with capacity limitations at each
city gate station. Referred to as city gate analysis, the design day hourly demand
generated from planning analyses must not exceed the actual physical limitation of the
city gate station. A capacity deficiency found at a city gate station establishes a potential
need to rebuild or add a new city gate station.

Network Design Fundamentals
Natural gas distribution networks rely on pressure differentials to flow natural gas from
one place to another. When pressures are the same on both ends of a pipe, the natural
gas does not move. As natural gas exits the pipeline network, it causes a pressure drop
due to its movement and friction. As customer demand increases, pressure losses
increase, reducing the pressure differential across the pipeline network. If the pressure
differential is too small, flow stalls, and the network could run out of pressure.

It is important to design a distribution network 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 Modeling
Developing and maintaining effective network design is aided by computer modeling for
network demand studies. Demand studies have evolved with technology to become a
highly technical and powerful means of analyzing distribution system performance. Using
a pipeline fluid flow formula, a specified parameter for each pipe element can be
simultaneously solved. Many pipeline equations exist, each tailored to a specific flow
behavior. These equations have been refined through years of research to the point
where modeling solutions closely resemble actual system behavior.

Avista conducts network load studies using DNV GL’s Synergi software. This modeling
tool allows users to analyze and interpret solutions graphically.

Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-3

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.1

Distribution System Enhancements
Demand studies facilitate modeling multiple demand forecasting scenarios, constraint
identification and corresponding optimum combinations of pipe modification, and
pressure modification solutions to maintain adequate pressures throughout the network.
Distribution system enhancements do not reduce demand, nor do they create additional
supply. 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
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.

1 This method differs from the approach that Avista uses for IRP peak demand planning, which focuses
on peak day requirements to the city gate.
Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-4

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. For pipelines experiencing
a relatively high and constant flow of natural gas, a large volume compressor installation
along the pipeline boosts downstream pressure.

A second option is the installation of smaller compressors located close together or
strategically placed along a pipeline. Multiple compressors accommodate a large flow
range and use smaller and very reliable compressors. These smaller compressor stations
are well suited for areas where natural gas demand is growing at a slower and steady
pace, allowing for installation of less expensive compressors over time to serve growing
customer demand into the future.

Compressors can be a cost-effective option to resolving system constraints; however,
regulatory, and environmental approvals to install a compressor station, along with
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.

Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-5

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 Chapter 3 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.

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
Chapter 2. This practice is consistent with the peak day demand forecast utilized in other
sections of Avista’s Natural Gas IRP.

Utilizing a peak planning standard based on a statistical probability method of historical
temperatures may seem aggressive since extreme temperatures are 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.

Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-6

Once a project/reinforcement is identified, the design engineer or construction project
coordinator begins a more thorough investigation by surveying the route and filing for
permits. This process may uncover additional impacts such as moratoriums on road
excavation, underground hazards, discontent among landowners, etc., resulting in
another iteration of the above project/reinforcement selection criteria. Figure 8.1 provides
a schematic representation of the distribution scenario process

Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-7

Figure 8.1: Distribution Scenario Process

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Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-8

Planning Results
Table 8.1 summarizes the cost and timing, as of the publication date of this IRP, of major
distribution system enhancements addressing growth-related system constraints, system
integrity issues and the timing of expenditures.

The Distribution Planning Capital Projects criteria includes:

• Prioritized need for system capacity (necessary to maintain reliable service);
• Scale of project (large in magnitude and will require significant engineering and
design support);
• 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 $500,000 in any year. The scope and needs of distribution
system enhancement projects generally evolve with new information requiring ongoing
reassessment. Actual solutions may differ due to differences in actual growth patterns
and/or construction conditions that differ from the initial assessment and timing of planned
completion may change based on the ongoing reassessment of information. The following
discussion provides information about key near-term projects.

Kettle Falls High Pressure Reroute, WA: 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 with construction anticipated in 2027.

Pullman High Pressure Reinforcement, WA: The Pullman high pressure reinforcement
will connect both the Moscow and Pullman’s high-pressure systems. This would bring
Moscow gas to Pullman, avoiding the need to rebuild the Pullman City Gate Station which
is currently exceeding its physical capacity. Additionally, this interconnection would
increase reliability as both Moscow and Pullman would then have two sources of gas.
Design is tentatively scheduled for 2023 with construction anticipated in 2024.
Construction timelines may change due to customer growth expectations.

Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-9

Table 8.1: High Pressure - Distribution Planning Capital Projects

Location 2023 2024 2025 2026 2027+
Kettle Falls High
Pressure Reroute, WA
(compliance-driven)
--- --- --- $100,000 $2,000,000
Pullman High Pressure
Reinforcement, WA $100,000 $6,700,000 --- --- ---

Table 8.2 shows city gate stations identified as possibly over utilized or under capacity.
Estimated cost, year, and the plan to remediate the capacity concern are shown.

These projects are preliminary estimates of timing and costs of city gate station upgrades.
The scope and needs of each project generally evolve with new information requiring
ongoing reassessment. 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 8.2 are periodically reevaluated to determine if upgrades
need to be accelerated or delayed. Those assigned a TBD year have relatively small
capacity constraints, and thus will be monitored. There are no plans to rebuild or upgrade
TBD city gate stations at this time.

Table 8.2: City Gate Station Upgrades

Location Gate Station Project to Remediate Cost Year
Rathdrum ID Chase #5000 Increase capacity $1,000,000 2023
Coeur d’Alene, ID CDA East #221 Rebuild for reliability $200,000 2023
Colton, WA Colton #315 TBD - TBD
Medford, OR Medford #2431 TBD TBD
Pullman, WA Pullman #350 Pullman High Pressure
Reinforcement, WA $6,800,000 2024
Sutherlin, OR Sutherlin #2626 TBD - TBD

Non-Pipe Alternatives
An evaluation of non-pipe alternatives is considered against pipeline capacity
reinforcements, when not related to safety, compliance, or road moves. Non-pipe
alternatives will only be considered when the cost of an upgrade is at a level high enough
where a non-pipe alternative may be cost-effective (i.e., greater than $500,000), 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. Possible non-pipe
alternatives include, but are not limited to, the following: uprating (raising) the existing
pipeline pressure, energy efficiency efforts including encouraging customers to adopt
more efficient appliances and equipment, and potentially electrification of natural gas
appliances. A non-pipe alternative must address any capacity concerns at a lower cost
versus the pipeline reinforcement to be considered a viable strategy.
Chapter 8: Distribution Planning

Avista Corp 2023 Natural Gas IRP 8-10

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Chapter 9: Action Plan

Avista Corp 2023 Natural Gas IRP 9-1
9. 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. The Oregon Public Utility Commission (OPUC)
provided a majority of the recommendations based on the Company’s 2021 IRP, while
others were derived from Washington and Idaho Commission Staff and Avista’s proposed
Action Plan items.

2021 IRP OPUC Recommendations
Recommendation 1: In the next IRP, use at least five years of historic data for modeling
use per customer.

This IRP utilizes a five-year use per customer coefficient for all Oregon territories in the
2023 IRP across all scenarios. For reference, a three-year coefficient was used for
Idaho and Washington.

Recommendation 2: Include a No Growth scenario in the next IRP.

Four scenarios were studied with no growth. These scenarios consider
Electrification with no new customers starting in 2024 and a hybrid heating
scenario where electric heat pumps are used with natural gas supplying
supplemental heat in cold temperatures. The results of these scenarios are in
Chapter 7.

Recommendation 3: In future IRPs, provide a comparison between the current CPA and
the last CPA, including a narrative explanation of major changes in the potential.

Please refer to Chapter 3 for a complete description of current and prior IRP CPA
reports.

Recommendation 4: Discuss demand response as a demand side resource option at a
TAC meeting before filing the next IRP.

Demand response studies were completed by Applied Energy Group (AEG) and
presented to the August and December 2022 TAC meetings. At this time demand
response is not cost effective and is not selected in any scenario. Please refer to
Chapters 6 and 7 for results of this analysis.

Recommendation 5: Discuss long-term transport procurement strategies at a TAC
meeting before the next IRP.

Chapter 9: Action Plan

Avista Corp 2023 Natural Gas IRP 9-2
Long-term transport procurement strategies were discussed in TAC 2 on May 3,
2022. This discussion included current supply side resources and contract
expiration dates along with renewal strategies.

Recommendation 6: Host a workshop within two months of the publishing of DEQ’s
Clean Power Plan Rules, to discuss challenges and opportunities to incentivize near-term
actions to reduce GHGs to meet Clean Power Plan targets, including consideration of SB
98 and SB 844 programs.

Avista held a TAC meeting in February 2022 to review the final CPP and its
implications to Avista including the challenges and opportunities of this program.

Recommendation 7: Provide a workshop in the next IRP development process to
discuss the possibility of using the social cost of carbon to help inform carbon risks in its
portfolios.

Avista utilized the social cost of greenhouse gas (SCGHG) for its energy efficiency
CPA in all three states. Additionally, a scenario using the SCC to value natural gas
versus other supply side resource options was performed and analyzed. Results
are in Chapter 7 and were presented during the TAC 4 meeting within the Demand
Side Management (DSM) and CPA presentations.

Recommendation 8: Include a non-zero carbon risk value for its Idaho customers.

In the 2023 IRP considers a national carbon cost for Idaho beginning in 2030.
Materials were presented in the TAC 4 meeting in September 2022. The values
used in this study are in Chapter 5.

Recommendation 9: Prior to the next IRP, conduct market research to reflect the
willingness of Oregon customers to pay for various carbon reduction strategies. Present
results at a TAC meeting.

Market research was conducted by Clean Energy Research and shared with our
TAC members in the August 10, 2022, meeting. The more significant results are
shown in Chapter 5.

Recommendation 10: Work with stakeholders and Staff to identify information that
should be included in an RNG project pipeline update and provide an update on the
Company’s RNG project pipeline as part of the next IRP Update, including, but not limited
to consumer risks and costs assessment associated with buy vs build RNG options.

The TAC was updated at the February 16, 2022 and December 15th, 2022 TAC
meetings. TAC members provided no feedback at those times. Chapter 4 provides
details around the project pipeline and process.
Chapter 9: Action Plan

Avista Corp 2023 Natural Gas IRP 9-3
Recommendation 11: In the next IRP, provide an analysis of the capabilities of Avista’s
system to accommodate hydrogen, where upgrades would be required to accommodate
hydrogen, and estimated costs of those upgrades.

As discussed during TAC meeting 5 held in December 2022, Avista can
accommodate a hydrogen supplier if the resultant gas meets existing tariff quality
standards and industry maximum blending percentages. Avista may inject the
hydrogen supply into a contained system where the end use customers have
equipment capable of accepting a hydrogen-blended gas. Avista will also require
metering and pressure regulation equipment at any interconnect point to measure
volume and gas quality and control supply pressure. Avista has an Interconnection
Agreement and application process ready for a hydrogen supplier. Avista has not
had any committed suppliers at this time. Any cost and/or upgrade will depend on
the proximity of the supplier to our distribution system.

Recommendation 12: In the next IRP, describe the assumptions for changes to
renewable technologies and their impact on future levelized costs in the text of the next
IRP.
Avista anticipates a reduction in green hydrogen and synthetic methane costs over
tie. Demand for these renewable technologies from state and federal policies along
with industry demand should increase overall demand for these carbon free
options. Also supporting programs and incentives such as the IRA, CCA, and CPP
all help to provide grants, loans, incentives, or equipment to help meet these goals.

Recommendation 13: Work with TAC to develop a scenario with a future large scale
supply interruption, like the October 2018 Enbridge incident

This IRP includes a supply interruption scenario, where an outage starting north of
Sumas at Enbridge and dropping down through Sumas. The scenario assumes
North capacity at 50% of available transport capacity rights. Included in this
scenario is an additional outage from the South at the Rocky Mountain region with
a 25% assumed outage. Results are found in Chapter 7. These scenarios were
discussed throughout the majority of the 2023 TAC meetings with additional
attention provided during the TAC 4 and 5 meetings.

Recommendation 14: In the next IRP, Avista should continue to keep the Commission
apprised of the Sutherlin and Klamath Falls city gate projects. The Company should also
provide a list of areas or projects where the Company is monitoring for capacity or
pressure issues.

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 5 meeting in December 2022. Please refer to Chapter 8 for a full
listing of projects Avista is monitoring at this time.
Chapter 9: Action Plan

Avista Corp 2023 Natural Gas IRP 9-4
Avista’s 2021 IRP Action Items
1. Further model carbon reduction in Oregon and Washington.

The PLEXOS model includes all carbon zero fuels and options in addition to
program elements to meet climate goals in Oregon and Washington.

2. Investigate new resource plan modeling software and integrate Avista’s system
into software to run in parallel with Sendout.

Avista procured a commercial off the shelf product called PLEXOS® from
Energy Exemplar in May 2021. This software was built and verified using
Sendout for initial model build. As mentioned during the TAC process the
additional complexity brought into the natural gas model with the climate
policies in Oregon and Washington made a parallel run impossible. The
additional functionality of PLEXOS® to model these new program requirements
was a primary reason Avista made the investment in the PLEXOS® application.

3. Model all requirements as directed in Executive Order 20-04

This plan includes the CPP by including yearly emission constraints,
community climate investments and zero carbon fuels as energy choices.

4. Avista will ensure the Energy Trust (ETO) has sufficient funding to acquire therm
savings of the amount identified and approved by the Energy Trust Board.

The ETO has received the necessary funding to acquire therm savings as
identified and then approved by the OPUC and ETO Board.

5. Explore the feasibility of using projected future weather conditions in its design day
methodology.

Avista utilizes a rolling 20-year average for both the demand and peak
forecasts using average temperatures projected for future weather conditions
from the River Management Joint Operating Committee (RMJOC). The
RMJOC includes BPA, US Army Corps of Engineers and the US Bureau of
Reclamation. The research team for these studies included the University of
Washington and Oregon State University. The data for these studies were
provided for Spokane, Medford, La Grande, and Klamath Falls to develop 19
different weather futures.

Chapter 9: Action Plan

Avista Corp 2023 Natural Gas IRP 9-5
6. Provide an update to the Oregon distribution projects referenced in Table 9.1 from
the 2021 IRP to understand capital costs outside of 2021 IRP expectations.

Table 9.1: Oregon Distribution Projects

Location Gate Station Project to
Remediate Cost Year
Klamath Falls, OR Klamath Falls #2703 TBD - 2023+
Sutherlin, OR Sutherlin #2626 TBD - 2023+

Large High-pressure distribution and City Gas projects did not occur since the
2021 IRP. Quarterly updates with OPUC Staff and other interested parties will
occur to ensure any change in projects is known along with reasons for any
major changes in expected capital expenditures.

2023-2024 Action Plan
1. Purchase Community Climate Investments for compliance to the Climate
Protection Plan for years 2022, 2023, 2024, 2025 and 2026 to comply with
Executive Order 20-04.
2. 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 ETO to
meet IRP gross savings target of 568,000 therms in 2024.
3. New program offered by ETO for interruptible customers in 2023 to save 15,000
therms.
4. 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.
5. In Oregon, acquire 8.64 million therms of RNG in 2023 and 21.80 million therms
of RNG in 2024.
6. In Washington purchase allowances or offsets for compliance to the Climate
Commitment Act for years 2023, 2024, 2025 and 2026 to comply with emissions
reduction targets.
7. Begin to offer a Washington transport customer EE program by 2024 with the goal
of saving 35,000 therms
8. Explore methods for using Non-Energy Impact (NEI) values in future IRP analysis
to account for social costs in Washington to ensure equitable outcomes.
9. Explore using end use modeling techniques for forecasting customer demand.
10. 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.
Chapter 9: Action Plan

Avista Corp 2023 Natural Gas IRP 9-6
11. Regarding high pressure distribution or city gate station capital work, Avista does
not expect any supply side or distribution resource additions to be needed in our
Oregon territory for the next four years, based on current projections. However,
should conditions warrant that capital work is needed on a high-pressure
distribution line or city gate station in order to deliver safe and reliable services to
our customers, the Company is not precluded from doing such work. Examples of
these necessary capital investments include the following:
• Natural gas infrastructure investment not included as discrete projects in IRP
– Consistent with the preceding update, these could include system
investment to respond to mandates, safety needs, and/or maintenance
of system associated with reliability
• Including, but not limited to Aldyl A replacement, capacity
reinforcements, cathodic protection, isolated steel replacement,
etc.
– Anticipated PHMSA guidance or rules related to 49 CFR Part §192 that
will likely 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