20250331Natural Gas IRP Appendices.pdf

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2025 Natural Gas IRP Appendices
TABLE OF CONTENTS: APPENDICES
Appendix 1.1 TAC Member List........................................................................ Page 1
1.2 OPUC Comments and Responses to the 2025 IRP Draft.....................3
1.3 WUTC Comments and Responses to the 2025 IRP Draft................16
1.4 Avista Corporation 2025 Natural Gas IRP Work Plan.........................25
1.5 IRP Guideline Compliance Summaries ..............................................33
Appendix 2.1 Avoided Costs........................................................................47
Appendix 3.1 Economic Considerations ..................................................................64
3.2 Customer Forecasts by State.............................................................73
3.3 Energy Intensity per Customer Class by State...................................74
3.4 Heating Degree Day Data.........................................................76
3.5 Annual Demand, Avg Day & Peak Day Demand (Net of DSM) ..........87
Appendix 4.1 AEG CPAs.........................................................................................91
4.2 OR Firm Customer CPA...................................................................195
4.3 Environmental Externalities..............................................................220
4.4 Annual DSM.........................................................................223
Appendix 5.1 Monthly Price Data by Basin...................................................225
Appendix 6.1 ICF Alternative Fuels Study..............................................................232
6.2 Weighted Average Cost of Capital ...................................................261
6.3 New Resource Options Costa and Available Volumes by Source....323
6.4 Alternative Fuel Volumes by Source..........................................339
Appendix 7.1 WA General Rate Case Compliance................................................348
Appendix 9.1 IMPLAN results.....................................................................354
Appendix 10.1 Distribution System Modeling...................................................360

10.2 Distribution within the IRP.......................................................364
Appendix 11.1 TAC Meeting #1........................ ..................................................366
11.2 TAC Meeting #2 ..............................................................................418
11.3 TAC Meeting #4....................................................................462
11.4 TAC Meeting #5 ..............................................................................530
11.5 TAC Meeting #6 ..............................................................................560
11.6 TAC Meeting #7 ..............................................................................572
11.7 TAC Meeting #8 ..............................................................................603
11.8 TAC Meeting #9 Draft ......................................................................638
11.9 TAC Meeting #9 Final .....................................................................671
11.10 TAC Meeting #10 ............................................................................698
11.11 TAC Meeting #11 .............................................................................822
11.12 Public Meeting.....................................................................856

APPENDIX 1 .1 : TAC MEMBER LIST
• - .
Applied Energy Group Kenneth Walter Andy Hudson
Avista Shawn Bonfield Catherine Mair
Kim Boynton Scott Kinney
Annette Brandon John Lyons
Terrence Browne Jaime Majure
Michael Brutocao Lisa McGarity
Josie Cummings Joey Nguyen
Kelly Dengel Austin Oglesby
Justin Dorr Tom Pardee
Grant Forsyth Heather
Rosentrater
James Gall John Rothlin
Amanda Ghering Erik Soreng
John Gross Jason Thackston
Lori Hermanson Jeff Webb
Mike Hermanson Jared Webley
Clint Kalich Michael Whitby
Biomethane, LLC Kathlyn Kinney
Cascade Natural Gas Company Brian Robertson Mark Sellers-
Vaughn
Bailey Steeves
Citizens Utility Board of Oregon General Email for
CUB
City of Spokane Logan Callen
Eastern Washington University Erik Budsberg
Energy Trust of Oregon Ben Cartwright Spencer
Moersfelder
Hannah Cruz Adam Shick
Kyle Morrill Willa Pearlman
Oregon Department of Energy Michael Freels
Oregon DEQ Nicole Singh Matt Steele
2025 Natural Gas IRP Appendix 1

Energy Strategies Jeff Burks
Fortis Ken Ross Jesse Scharf
Idaho Public Utility Commission Donn English Mike Louis
Michael Eldred Victoria Stephens
Terri Carlock Jason Talford
Rick Keller Joseph Terry
Kimberly Loskot Taylor Thomas
Intermountain Gas Raycee Thompson Lori Blattner
Dave Swenson
Lewis and Clark Law School Carra Sahler
Metro Climate Action Team Pat Delaquil
Northwest Energy Coalition Charlee Thompson
Northwest Gas Association Dan Kirschner
Northwest Natural Gas Michael Meyers
Northwest Power and Conservation Council Steve Simmons
Oregon Public Utility Commission JP Batmale Kim Herb
Ted Drennan Sudeshna Pal
Puget Sound Energy Jennifer Coulson Hannah Wahl
Gurvinder Singh
RNG Coalition Vincent Morales
Sierra Club Jim Dennison
Washington State Office of the Attorney Jean Marie Dreyer Stefan de Villers
General
Washington Utilities and Transportation Sofya Attitsogbe Byron Harmon
Commission
Emily Gilroy Heather Moline
2025 Natural Gas IRP Appendix 2

Appendix 1 .2: OPUC Draft Feedback
PreferredChapter 2: Resource StratM Avista's Response
1. Per Recommendation 3, Staff appreciates Avista's
efforts to develop alternative resource portfolios.
The 5 presented scenarios, as well as 12
sensitivities applied to the PRS, provide desired
insight as to how the selection of resources varies
across different futures. _
2.While expressed as a recommendation Distribution is not
(Recommendation 5)for future Avista IRPs, Staff expected to exceed
appreciates Avista's modeling the comparative forecasted projects
costs for a high-growth scenario as well as a high- currently found in Chapter
electrification scenario,which begin to address 10 in any case modeled in
Recommendation 5 urging Avista to model all the 2025 IRP. However, if
relevant distribution system costs and capacity new large customers
costs as well as describe the associated projects- request service in a
needed-, and costs-incurred-,from high and low specific area not forseen
load scenarios. Staff requests that Avista's filed IRP in these distributionupgrades it may require
specify any differences in anticipated near-term additional distribution
procurement (including specific projects which needs other than those
Avista might already be considering) between the projects included. It is
high load scenario and the PRS. unknown how Avista
would estimate the
location and upgrades
needed, if any, unless
specifics around volumes
and location are provided
by these large customers.
3. In the filed IRP, please include a narrative Updated in the document
description about the drivers of alternative fuels in Chapter 6.
resources selection in the high and low-cost
alternative fuel cost sensitivities.
Chapter 3: Demand Forecast
1. Staff appreciates Avista basing its load forecast
upon the RCP 4.5 GHG mitigation scenario, its
description of the implications of the varying RCP
scenarios, and its estimation of future temperatures
and modeled HDD's.
2025 Natural Gas IRP Appendix 3

a.Additionally, Staff recognizes Avista's inclusion of
a scenario of future weather informed by the RCP 6.0
model, per Expectation 5.
2. Staff recognizes, per Expectation 3,that Avista
modeled a load forecast reflecting GCM trends and
appreciates the Company's responsiveness in its
downscaling of the Multivariate Adaptive
Constructed Analogs (MACA) methodology to its
Oregon service territory regions of Medford,
Roseburg, and Klamath Falls.
3. Per Expectation 9, Staff appreciates Avista's Updated in the document
application of IRA credits to the specified in Chapter 7. In short, in
electrification resources including space heating, the absence of the IRA all
water heating, and other appliances across resource costs would be
residential and commercial customers. Staff asks expected to increase
that Avista, in its IRP, describe whether and how
policy uncertainties surrounding the IRA have an
impact on Avista's modeling for electrification.
4. Per Expectation 8, in the filed IRP, please describe This can be found
how the line extension allowance decision from specifically in the "No
Docket No. UG 461 is reflected in the load forecast Growth" case in Chapter
modeling. 8. Oregon and
Washington line
allowances go away in
2026 and 2025
respectively. The building
code requirements in
Washington are expected
to drastically reduce new
customers to the LDC, but
in Oregon similar building
codes have yet to include
the requirements for heat
pump related space and
water heating. Avista will
continue to monitor new
customers added to the
system to provide updates
on how the line extension
policy may change
customer hookups to the
LDC.
2025 Natural Gas IRP Appendix 4

5. Per Expectation 6, Staff requests that Avista This can be found
include in its 2025 IRP Update, a scenario of no specifically in the "No
future customer growth beyond 2027. Growth" case in Chapter
8. Oregon and
Washington line
allowances go away in
2026 and 2025
respectively.
Chapter 4: Demand Side Resources
1. Per Recommendation 7, in the filed IRP, please Avista does not have AMI
describe whether the Company used advanced located in it's Oregon
metering infrastructure (AMI) data and Form 10Q territory so this is not an
data to capture customer behavior, as expected available avenue for this
through Expectation 7(originally Staff IRP. Instead of the
Recommendation 7)from Order No. 24-156. options in
recommendation 7 Avista
contracted with AEG to
develop an end use
forecast to estimate the
number of customers that
may choose to naturally
convert to electric end
uses.
a. If AMI and Form 10Q data weren't used in inform With the lack of detailed
the rate of electrification occurring naturally among information in a 10Q and
Avista customers, in the filed IRP, please describe no AMI infrastuucture in
Avista's reasoning for not deploying such Oregon, Avista
methodology and any feasibility challenges faced by
the Company in doing so and what steps might need
to be taken to consider inclusion of this data in the
Company's 2027 IRP.
Chapter 6: Supply-Side Resource Options
2025 Natural Gas IRP Appendix 5

1. Per Expectation 2 from Order No. 24-156, Staff Avista has provided this
requests that Avista include in its 2025 IRP Update-, update in Chapters 5 & 6.
an RNG procurement update including a comparison An annual alternative
of projected and actual procurement; RNG prices fuels RFP was released in
secured; a description of how the Company has 2024. With the CPP rules
leveraged other carbon markets to reduce RNG not yet finalized, costs
costs; and how the Company is applying the were not available to
environmental attributes of the RNG procured to compare program offsets
CPP compliance. (CCIs) to these alternative
fuels. An RFP will be
released in 2025 to help
measure resource options
to secure the least cost
resource for CPP
compliance.
2. Staff request that Avista provide to Staff all of the A full resport is available
details, data and assumptions associated with ICF's in Appendix 6
study for modeling available-, and technical
potential-,volumes and prices of alternative fuels
[See Figure 6.4]
3. Hydrogen, CCUs and synthetic methane projects Neither Hydrogen nor
seem to be planned to take effect after 2030 and Synthetic Methane is
2037. In the filed IRP, please explain how is selected in the PRS.
modelling addresses Staff's concerns in the CCUS is selected, but due
previous IRP about procurement and readiness of to uncertainty around
adoption of emerging alternative fuel options. costs and practicality,
further time is needed
before considering this
resource in an action plan.
Chapter 7: Policy Considerations
1. Concerning Request No. 10 from Staff's report Updated in the Chapter
included in Order No. 24-156, Staff appreciates
Avista's demonstration of costs associated with
CCIs. Staff further requests that Avista include price
forecasting for the nominal per metric ton of carbon
dioxide equivalent (MTCO2e), parallel to Figure 7.4,
for renewable thermal credits (RTCs).
Chapter 9: Customer Equity and Metrics
1. Please provide any information and workpapers Implan NEI summaries
associated with the NEI study conducted by ICF. are available in Appendix
9.
Chapter 10: Distribution Planning
2025 Natural Gas IRP Appendix 6

2. Staff recognizes and appreciates Avista's
presentation and detail of the updates to the
Company's methodology for analyzing NPAs, as
previously detailed in Expectation 23 from Order No.
24-156.
3. Staff appreciates Avista's update regarding the
latest information on possible distribution projects,
including any proposed traditional investments or
proposed NPA, as requested by Staff Request 4 in
Order No. 24-156.
Chapter 11:Action Plan
1.The Draft IRP does not mention or include the Updated to include these
assumptions of pipeline project Aldyl A in 2037, details
which is in the process of being replaced, nor its
implications on supply side projections. Staff
requests that Avista describe any relevant
assumptions and impacts to supply side
projections, of the Aldyl A project,within its 2025
IRP.
n en itiviti a
Topic Staff Feedback Avista Response
Responsiveness to Order 23-156
Recommendation 3:Regardless of the Staff reiterates its appreciation for
analytical approach taken to create Avista's modeling of 5 scenarios
the PRS,future IRPs should include including the PRS(or base case),and 12
alternative resource portfolios that sensitivities. Staff looks forward to
represent different utility decisions. reviewing all forthcoming workpapers
and additional information regarding the
refined set of scenarios and sensitivities
provided by Avista.
2025 Natural Gas IRP Appendix 7

Staff notes that while chapter 8 The PRS is the expected case with load
incorporates several scenarios,the growth and future characteristics we
sensitivities seem to focus on the primarily plan for furture resources and
baseline PRS with less exploration of costs.Other scenarios,while important,
other scenarios.Staff requests that are not directly comparable to the PRS
summary descriptions figures,and because of different futures.If one were
associated analysis are provided for the to compare them,inaccurate outcomes
resiliency and diversified portfolio would occur as the future has changed.
selection scenarios,which parallel those These alternative growth/demand
included for the PRS,social cost of futures are to estimate costs and risks in
greenhouse gas,and no climate the event they occur.For example,
programs scenarios(pages 8-4 through choosing a set of resource for the"high
8-6 of the draft 2025 IRP). electrification"scenario is not
comparable to the PRS as the
expectations vastly differ from one
another.Comparisons are made
available throughout chapter 8 showing
how resource selections and costs
differ.
Staff requests that Avista further clarify
whether:
• The resiliency and diversified Resiliency and Diversified portfolios are
portfolio selection scenarios should be considered a scenario as shown in Table
included under the section for sensitivity 8.1. They have numerous changes like
forecasts. weather,peak demand or resources that
are forced in(Diversified Portfolio)to
consider reliabillity and costs of these
resources.
• The presented high electrification adjusted language in the high
sensitivity is indeed a sensitivity or rather electrification case from"scenario"to
a scenario,given the introductory "sensitivity".It is a sensitivity as the load
language on page 8-11,"This scenario reduction begins with expected loads in
considers a loss of demand due to the PRS and drives downward each year
building electrification...". by an average of 4%.In this case,only
the served load changes with resources
selected around this new load.
• The removal of the high load growth The High growth sensitivity is an
scenario,between what was presented alternate case to show a higher than
duringAvista's TAC meeting number 2 expected demand from increased
(April 4,2024)and the draft 2025 IRP, customer growth.Although Avista
was the result of feedback provided by considers this unlikely,it does help to
TAC members.If so,Staff requests that show risk bands for plausible future
Avista cite any feedback used its outcomes.This case can be found in
decision-making process. Chapter 8.
2025 Natural Gas IRP Appendix 8

Recommendation 4:Future IRPs Staff appreciates Avista's Avista has provided this illustration in
should include stress testing of the responsiveness to the application of Figures 8.32 to 8.38 to show the risks of
PRS and alternative resource stress testing to the presented these scenarios through 500 Monte
portfolios and provide metrics scenarios,as discussed on page 8-3 and Carlo draws to estimate alternative fuels
comparing the severity and variability Figure 8.34.In Avista's 2025 IRP,Staff volumetric risk,price risk of resource
of risk in alternative portfolios. requests that a similar analysis is and demand risks from varying weather.
provided for the alternative scenarios Additionally,these costs and risks are
and their selected portfolios,as is shown in Figures 8.24 to 8.26.
provided for the PRS in steps 1-4
outlined on page 8-33.
As mentioned earlier,the current focus Monte Carlo runs are helpful to
of the alternative scenario analysis is understand risks for the selected
based on the baseline PRS,Staff resources based on the specific
believes that the value of the stress changes.When comparing scenarios
testing would be greater if it were also and sensitivities,a deterministic model
conducted on alternative resource is useful to help show cost variability
portfolios,with PRS results presented based on different assumptions.If Avista
alongside alternative portfolios results. were to compare all scenarios and
Doing so would help assess decisions sensitivities,based on statistics,the
the Company may make,and the risks costs would average out to roughly those
associated with those decisions, costs as depicted in the deterministic
resulting in an even more useful planning scenarios.For this reason,using Monte
process. Carlo on all cases evaluated is not
helpful as they use the same values.The
PRS is the most reasonable to run a
Monte Carlo for risk of differing prices,
loads and volumes available as it is the
expected future.
Recommendation 6:Avista work with Staff appreciates Avista's efforts to work
the TAC to develop additional with the TAC to develop sensitivities
scenarios and sensitivities for the next according to high-,and low-,costs for
IRP,including for example:greater low carbon resources,as demonstrated
price variation for low carbon in Figures 8.7 and 8.14 respectively.Staff
resources,high-cost for low carbon further observes that Avista provided a
resources,omission of any highly scenario that considers current
uncertain resource,or utilization of resources used for the 2025-2045-time
only existing resources. horizon through its No Climate Programs
scenario.Additionally,Staff recognizes
Avista's efforts to explore alternative
fuels like hydrogen,RNG and synthetic
methane,and modeling the uncertainty
surrounding their adoption.While Staff's
feedback here does not represent its
final findings,Staff understands Avista's
efforts listed above as the Company
being responsive to Recommendation 6
from Order No.24-154.
2025 Natural Gas IRP Appendix 9

Request 1:Future IRPs should include Staff appreciates the additional detail
a clearer explanation of the PRS,and a regarding the development of Avista's
more transparent presentation of the PRS and associated stress testing on
assumptions and processes used in page 8-33,as well as the detailed
creating the PRS,including examples information regarding modeled supply
noted by Staff. and demand side resources in chapter 2.
Expectation 6:For the next IRP, Staff recognizes that Avista models a Based on feedback and for transparency
include a scenario of no future demand forecast of 0.68%lower than a no growth case is included in Chapter
customer growth beyond 2027. previous submissions in 8.In the draft version,Avista did not
acknowledgement of the actual show a no growth case as many other
anticipated low demand projection in scenarios show the same demand
Oregon and Washington going forward. trajectory including the Low Natural Gas
However,Avista doesn't appear to model Use Case.
a no customer growth scenario.Staff
reiterates its request that Avista include
in its 2025 IRP a scenario of no future
demand/customer growth beyond 2027
to fully understand the implications of a
flat customer base on the system
demand and long-term cost structures.
2025 Natural Gas IRP Appendix 10

Expectation 10:Scenarios and Staff appreciates the efforts that Avista Uncertainties include expected weather
sensitivities developed for the next IRP has made in the employment of by planning region impacting demand,
should include complex possible stochastic modeling and Monte Carlo volumetric availability of alternative
futures that capture plausible sources simulations to assess the variability fuels,peak day planning with increasing
of risk due to uncertainty;Avista across multiple portfolios and scenarios or decreasing loads,natural gas price
should explore its resource portfolios providing some level of analysis to volatility,and alternative price volatility.
against these scenarios.Avista should evaluate risk. Avista modeled 9 cases where demand
run stochastic analysis for price and specifically is varied from the PRS and
demand assumptions consistent impacts to the resources required and
within scenarios and report risk timing of those resources.The weather
severity metrics for each scenario. stochastics can be found in Figures 3.27
to 3.31. Additionally,price risks for
natural gas can be found in Figures 5.4
and 5.6 for the 500 stochastic prices
used in the IRP.Alternative fuels risk is
shown in Figures 6.16 to 6.21 by
resource type.The combination of these
risks is evaluated in Chapter 8 under the
Monte Carlo Risk Analysis section.All
identified scenarios are run through a
500 draw monte carlo risk analysis and
the PRS,and it's expected case
attributes,are further run through a set
of 5-500 draw Monte Carlo analyis by
portfolio%to help determin the lowest
risk and cost set of resources in our
expected future.As mentioned
previously,running stochastics on
alternative sensitivities would all average
out to what is being shown in the
deterministic runs as the same data sets
are used for all scenarios and don't differ
as this would not be comparable or help
find a solution to the expected load.
Efforts will be made continually to
address these scenarios to provide as
2025 Natural Gas IRP Appendix 11

Page 8-3 explains that the scenarios accurate of growth and cost
"consider plausible futures with critical expectations as possible.Avista
uncertainties...".In the filed IRP,Staff continually estimates short term
asks that Avista provide a description of demand and reflections in actual
uncertainties considered in their variations compared to future
modeling,how they are reflected in that expectations will be included in future
modeling,and explain whether and how IRPs.In the event these expectations
uncertainties resulted in changes in the begin to drastically differ from
scenarios,and how they would influence expectations Avista will include the
the utility's decisions. savarity of these changes in demand
growth and load expectations.
Expectation 16:The next IRP include Staff appreciates that Avista has Additional description has been added to
electrification modeling assumptions included high electrification as part of its the High Electrification case.In short,
that decrease capacity costs, sensitivity analysis.In the filed IRP,Staff costs may go down once
distribution system costs,and other asks that Avista clearly describe and decommissioned,but if a single
appropriate expenses corresponding support all electrification modeling customer were to remain on the line,
with reduced demand from assumptions,and explain how those Avista would be required to maintain the
electrification assumptions reflect decreased capacity safety and reliability of any individual
costs,distribution system costs,and any lines.The methodology to identifythese
other appropriate expenses specific lines is not available in CROME
corresponding with reduced demand as it is a resource optimization model
from electrification.Staff requests that intending to solve least cost/risk for
Avista specifies any differences in demand and available resources. The
assumptions used forthe modeling of planned distribution upgrades in Chapter
electrification in its 2025 IRP PRS relative 10 would still be required as these
to its 2023 IRP PRS. upgrades are necessary in the short
term.No distribution projects are
expected outside of the 5 year action
plan.
2025 Natural Gas IRP Appendix 12

Expectation 17:Future IRPs should Staff seeks clarification regarding All scenarios include increased
include a scenario with significantly whether Avista's electrification residential heat pump adoption as
increased residential heat pump sensitivity is how the Company is being described in Chapter 3.Naturally
adoption and the corresponding shift responsive to Expectation 17.In the filed occurring heat pump adoption,among
in winter load from the gas system to IRP,for the high electrification other end uses,are shown in Figures 3.9-
the electric system. sensitivity,Staff requests that Avista 3.14. Additionally,the demand by state
attempt to distinguish between the in Figures 3.5to 3.9 show the amounts of
impacts to forecasted load of demand by end use remaining in the
electrification through increased heat PRS.Similar percentages can be derived
pump adoption as opposed to the based on these percentages for the high
electrification of other equipment. electrification case.The hybrid case is
also useful in this expectation.
Expectation 18:Avista should work Staff appreciates Avista's inclusion of A monte carlo analysis was not run for
with the TAC to more fully explore and Hybrid Heating sensitivity which allows the same reasons as mentioned above
model the potential of dual fuel heat for the impact of electric heat pumps (recommendation 4).Avista did further
pumps in the next IRP,for example by alongside natural gas furnaces. modeling on the heat pump and COP
ensuring that the use of some dual fuel However,Staff cannot determine curve to allow for additional uptake in
heat pumps is represented in Monte whether a Monte Carlo analysis was heat pumps outside of naturally
Carlo risk analysis conducted in which historical dual fuel occurring electrification as discussed in
heat pump data is used to construct a expectation 17.
probability distribution;forwhich a
specified percentile of hybrid heating updates and descriptions have been
load-impact over the 2025-2045 time made to this case and can be found in
horizon is applied to the PRS's load chapter 8.
forecast.However,Staff cannot
determine whether a Monte Carlo
analysis was conducted to capture the
probability and range of potential
adoption rates for dual fuel heat pumps
over the 2025-2045 horizon.Staff
requests that Avista provides a
description of the hybrid heating
assumptions including the sources of
data used and how the data informed
load forecast. In the filed IRP,please
describe how the stochastic analysis
was used to represent uncertainty
around dual fuel heating uptake and
ultimately through PRS.
2025 Natural Gas IRP Appendix 13

Expectation 20:Staff expects Avista to Staff recognizes Avista's efforts to model Avista did not consider this for the
work with the TAC to identify a PAC IRP electrification scenarios and sensitivity following reasons:
scenario reflecting electrification that analysis and appreciates its work in -in order to get a scenario from PAC and
Avista might use to generate a load attempting to capture electrification sufficient data to accurately depict in an
forecast for its next IRP.Before the costs in overlapping electric territories. electrification scenario,Avista would
next IRP,Avista should work with PAC It is Staff's understanding that Avista has need to work with all IOU,PUD,and CO-
to collect the load forecasts used in not included other PacifiCorp's load Ops to get their costs and estimates as
planning that most closely reflects a forecasting in its electrification scenario well for an accurate comparison of
building electrification scenario for the modeling to date.In its filed IRP Staff electrification growth by area.Otherwise
overlapping territories.With these asks that Avista describe its efforts to be it's taking only a piece of growth
Load forecast results,Avista should responsive to this expectation and expectations into consideration.For
discuss with PAC supporting provide any outcomes of this effort to example:If we were to only get this
commentary regarding supply-side date. information from PAC and apply it to La
and demand-side resource impacts, Grande with Oregon Trail Electric or the
rate impacts,and associated GHG City of Ashland,these growths may not
emissions with each scenario/ be comparable due to climate and
portfolio.Avista should discuss with economic factors.Another concern is
the TAC the extent to which the which forecast we use for these efforts?
Company might be able to model the Is the most recently filed IRP appropriate
equivalent in its next IRP. or should it be based on the last
acknowledged IRP for PAC? Finally,in
these service areas outside of PACs
service territory what is a reasonable
recent forecast in terms of time frame to
use in these cases with the
understanding they may not provide
growth projections as they may not
submit a bi-yearly filing?
Avista will look for possible
methodologies to consider this in the
2027 IRP and may reach out to the OPUC
to help guide this effort.
Other Feedback
Miscellaneous Staff notes that chapter 8,page 33, All figures will be corrected in the final
addresses Figures up to 8.40 and that IRP filing
Figures 8.37-8.40 appear to be missing.
Please include Figures 8.37-8.40 within
Avista's 2025 IRP.
CROME Modeling&Workpapers Staff requests that Avista provide to the Avista will have all available non-
Commission at the time of filing all confidential workpapers posted to the
supporting workpapers for Avista's IRP website by the filing date. Any
CROME modeling of its PRS as well as confidential workbooks such as CROME
alternative scenarios and sensitivities can be made available through a
modeling confidential filing with the commissions
2025 Natural Gas IRP Appendix 14

Monte Carlo Risk Analysis and At the time of filing,please provide any These will be provided at the time of filing
Workpapers workbooks detailing the historical data
used in Avista's Monte Carlo risk
analysis,particularly concerning natural
and renewable gas prices,allowance
prices,and weather forecasts as noted
on page 29(of chapter 8)of Avista's 2025
Draft IRP.
2025 Natural Gas IRP Appendix 15

Appendix 1.3: WUTC Draft Feedback
ResponseFeedback
1.Accessibility and Equity Considerations
• Consider revising the Introduction (p.1)for Added language for clarification
accessibility by using plain language to enhance
comprehension.
• It may be helpful to ensure that procedural equity Avista has clarified this sentence and
is considered throughout the document, making it has tried to do the same for the entire
more accessible for interested parties with varying document.
levels of technical expertise (e.g., p. 1-9: "Trended
coldest on record to the% of overall weather
future reduction in heating degree days by 2045",
and p. 20-5: "Carbon Policy Resource Utilization
Summary").
• Consider assigning the same color to the resource Updated in document
on all figures(e.g., Figures 2.21-2.25).
2. Data Transparency and Clarity
• Figures 2.7-2.10
o These figures might benefit from showing Avista will work to provide an updated
change over time in a different format. format for these figures in the 2027 IRP
o Improving the placement of these figures Updated within the document.
so they are closer to their relevant
discussions would enhance readability and
comprehension.
o Does average case demand mean year- Average case demand uses a 3 year base
around daily average or the average on a and heat coefficients by area, combined
peak day? with expected EE and excludes peak
� days
o Consider disaggregating these figures for Updated document for all cases
each service area.
• Clarifications on customer classification:
o Further elaboration on how future policy Updated in the document
changes might affect different customer
segments would strengthen this section.
o Consider providing rate impacts analysi Updated in chapter 8 to compare to all
here. cases
t3Mjodeling and Methodology Considerations
CROME Model:
o Would it be possible to provide us with Avista staff is available for questions or
training or resources to help us better training on this model at any time
understand and utilize this model?
o Are there any available plugins or A"What's Best" license from Lindo
extensions that Staff might need for Systems would be required to recreate
recreation of the results? these results
2025 Natural Gas IRP Appendix 16

o Figures 2.1-2.3: in Resource Integration, These service areas are based on
you state that you forecast 11 service physical deliverability of pipelines and
areas. Consider adjusting the figures to are grouped to provide results for
reflect that. demand regions to provide an
understanding of what is needed to
serve these specific areas.
• Electrification Assumptions (p.13, p.35, p.50):
o Some stakeholders might benefit from No stakeholder feedback has been
additional clarity on whether assumptions provided to Avista during the TAC
regarding voluntary electrification and gas process or in the meeting,to date. If
demand decline are too conservative or feedback is provided, we will consider
need adjustment. altering these expectations in the 2027
IRP.
4. Greenhouse Gas (GHG) Compliance
o Figure 2.5: consider reflecting the auction For clarity purposes, it may confuse the
ceiling and floor prices on the graph. general reader.This is available in
Figure 7.8.
o Would transport customers have access to Updated in the document
the same compliance mechanisms?
Clarifying this could be useful.
5. Resource Planning and Future Demand
• Figure 2.6: this x-axis might be clearer if you use Avista tried to find a format but was
month names. unsuccessful. We'll work on this for the
2027 IRP.
• "This IRP assumes pipelines will file to recover costs If rates come in higher or lower based
at rates equal to increases in GDP." -What would on customers and the tariff design,
be the implications of this assumption? (p. 2-5) costs of transporting this gas may
change the least cost resource
selections.
• How would the portfolio behave in the case of Avista currently obtains 83%of its total
Canadian tariffs on gas imports, particularly from natural gas from Canada and 17%from
AECO? the Rockies region. Historically, AECO is
the lowest cost basin and while adding
10%tariffs to this gas,the overall
resource selection is unlikely to change
due to this gas being least cost along
with our interstate transportation
rights deliver from Canada.
• Figure 2.3: WA territory is larger than OR, but the The analysis is completed by two
figure shows similar load served by EE. What is the separate entities,AEG (ID/WA) & ETO
reason behind it? (OR). Methodology differences
between models may account for some
of the changes.Avoided costs will also
differ between OR and WA based on
resource selections and climate
programs. The CPAs for both entities
can be found in Appendix 4.
2025 Natural Gas IRP Appendix 17

• Figure 2.18: is it possible to see a stacked graph There are slight additions to customers
that accounts for the causes of the decline in in the PRS across the 20 year planning
demand? How much of this is attributable to horizon.This means all demand is
customer losses? attributed to energy intensity of end
products gain in efficiency from
building codes and energy efficiency
program savings. Fewer HDDs add to
the declining demand.
• Table 2.5: RNG in 2038 and 2039—how would this The CROME model purchases
be implemented? alternative fuels resources based on
system needs and least cost.The model
decides how to serve these objectives
including the energy needs and
emissions goals. Overall, OR takes the
vast majority of RNG.
• Figure 2.21: Who pays for these allowances?Avista Avista has the obligation to comply with
who passes them on to transport customers? Or the CCA for all customers under 25k
the transport customers? How do these allowances MTCO2e.This analysis considers all
factor into the lowest reasonable cost analysis? Is customers meeting this criteria, but
this data Avista received from its transport pulls out transport customers
customers? Is it a suggested compliance strategy specifically to show the overall impact
for transport customers on which Avista has no needed to comply with the CCA. Any
influence? transport customers above this 25k
MTCO2e need to comply to the CCA
considering their own options and
selections. Avista does not model these
suppliers.
• Figures 3.1-3.3:The rationale for projected gas Updated charts in section. In
demand growth might need further explanation, Washington, little to no growth is
especially considering policies encouraging expected for residential, commercial or
electrification and decarbonization. industrial customers. Energy intensity
per customer pulls demand down
through the forecast horizon.
• Figure 3.4:the 2013 customer survey data might be Avista agrees and has this updated data
too old and benefit from updated data. Consider consideration in its current statement
using NEEA 2022 residential stock assessment in of work for conservation potential
place of 2016 one. Consider using 2018 MECS assessments for future analysis and IRP
(released in 2021) in place of the 2015 study. documents.
• Figure 3.7: the data doesn't appear congruent with Figure 3.7 includes building codes
Figure 2.23. What is the reason for it?Why does reducing the energy intensity per
demand in 3.7 go down without DSM? customer and a declining number of
HDDs throughout the forecast horizon.
• "The demand forecast only includes customer This is intended to state the higher
driven electrification decisions, where a customer efficient products will be switched out
has the option to replace the existing gas space or at the end of life with a more efficient
water heating equipment with electric alternatives, product.At a system level this means
includes purchase decision logic copied from the more and more customers will naturally
2025 Natural Gas IRP Appendix 18

U.S. DOE's National Energy Modeling System."— drive down demand due to a lower
What is the change in customers due to this? If energy intensity per customer.
residential customer counts appear steady but
demand trends downward w/out DSM does that
mean Avista is losing more energy intensive
customers and gaining less intensive customers?
• What are the drivers behind commercial customers The primary driver for the WA
growth in WA? commercial customers is the building
code requirements
• Table 3.2: How much of the decline is attributable Some of these demands are
to climate change, end-use technology, building attributable to climate change and less
codes, building shells, and electrification each? HDDs, but the primary decline is from
building code requirements that drive
electrification of WA commercial
customers.
• Figure 3.15: what is the standard deviation here? Is The standard deviation of space heating
it possible to see box and whisker plot? is 53 therms,water heating is 2 therms,
secondary heating is 1.1 therms,
appliances is 0.7 therms.
• Weather stochastics: Additionally to comparing a Avista likes this idea and will implement
30-year period to a 20-year period, is it possible to this in future IRPs
divide them into 15 year chunks and compare into
year-by-year?
• Figures 3.22-3.26: could you share with us the We will post on Avista's IRP website
datasets for these figures?
• Could you clarify this sentence: "Historic The data sets provided in the weather
temperatures are used as the standard deviation of futures have a large difference in
these values as there is more data to draw standard deviations.To normalize the
information from with actual temperature weather and not create exceedingly
variation to measure these mean HDD expectations high HDDs a historic dataset was
variability." utilized.
• Consider presenting the datawith the planning Unfortunately, our data does not go out
horizon of 2050-in line with the deadline for to 2050. In the 2027 IRP we will provide
greenhouse gas emissions limits in accordance with all data to go to this timeframe.
Climate Commitment Act and RCW 70A.45.020.
6. Public Engagement
• Differentiating between who was invited vs. who Updated in document
attended TAC meetings might provide a clearer
picture of stakeholder engagement.
General Comments on Data and Figures
0 Mitigation of CPA Data Staleness: Could you Avista agrees and has this updated data
provide more detail on how Avista is addressing consideration in its current statement
the potential impact of outdated CPA data on of work for conservation potential
planning results?This would offer stakeholders assessments for future analysis and IRP
more confidence in the robustness of the analysis. documents.
2025 Natural Gas IRP Appendix 19

o Real vs. Nominal Dollars: Please indicate whether All figures are in Nominal dollars. For
figures present nominal or real dollars. Our the 2027 IRP we would be open to
preference would be for real dollars to ensure reporting results in real $.
consistency and comparability.
o Comparative Metrics Across Jurisdictions: Including Avista will consider this in the 2027 IRP
comparisons among Washington, Oregon, and
Idaho—such as EE Dth per customer and EE dollars
per customer—would provide useful regional
insights.
Chapter 4: Demand-Side Resources
o Figure 4.1: Oregon's avoided cost appears The avoided costs are the beginning of
significantly lower than Washington's. How does the analysis performed by the ETO.
this difference impact conservation acquisition? Further considerations are
implemented as described in Appendix
4.
Due to the CPP covering emissions in
the first compliance period the avoided
costs are lower than in WA where the
cap decline is much higher with 7% in
the first 2 compliance periods, requiring
additional allowances to meet program
requirements.
o Figure 4.2: Consider adding a narrative explanation The costs shown in these figures
or modifying the data presentation for Total Utility represent incremental costs by year
Cost.The sharp bend in 2035 raises questions— with cumulative therms savings. Each
why is Avista anticipating a reduction in total utility year has individual costs for
costs after 2035?Additionally, aligning the graphs' implementation of the savings, but the
timelines (either both cumulative or both yearly) savings are carried forward where no
would improve clarity. additional costs are involved and that is
why we show this as depicted in these
figures.
o Table 4.1: What is driving the conservation target Please see Appendix 4, for the full
to double between 2026 and 2027?Additional description of costs and savings in these
context would be helpful. timeframes.
o Demand Response Program: Consider adding a Demand response was not selected and
discussion on the expediency of DR due to the overall small savings and
implementation and how Avista plans to scale high costs Avista does not plan on
participation. implementing a DR program at this
time.
o Building Electrification: We couldn't find further Updated in Document
discussion of electrification in Chapter 7. Could you
provide a page reference for easier navigation?
o Page 4-18:The first sentence could be rewritten for Sentence has been updated to provide
better clarity. more clarity.
o Figures 4.16 &4.17: Consider aligning the x-axis Figures have been updated
direction to flow from negative to positive, as this
is the expected format for most readers.
2025 Natural Gas IRP Appendix 20

o Figure 4.17: An overlay histogram showing the Avista will consider this in the 2027 IRP.
distribution of temperatures in a representative It's a great idea!
region would improve visualization.
o Figure 4.19: Could you confirm whether these Nominal $ and added language to
figures are in real or nominal dollars?Also, does clarify that they do include estimated
this graph reflect the cost of electric business generation,transmission and
expansion? distribution from 2025 Avista electric
IRP.
o Electrification & Heat Pump Modeling: Will the The workbook will be available on the
modeling workpapers be included in the final IRP Avista IRP website along with many
filing? other inputs and considerations for
data within this IRP.
o Figure 4.20: How do these electric cost projections See Figures 4.21—4.24 for a
compare to gas costs? comparison in dekatherms and Figure
5.5 for natural gas pricing
o Figure 4.21: Consider adding gas heating costs as a Estimated heating costs can be found in
baseline for comparison. Figure 5.2-5.5
o Figure 4.23:The orange line does not have a Figure has been updated (thanks)
corresponding key, could you clarify?
o Electrification Assumptions:The IRP states that These costs are averaged based on #of
81%of natural gas customers in Washington are meters estimate by service area with
expected to transition to Avista for electricity, the costs being included within the
while 19%would switch to public power providers electrification analysis for the cost per
(e.g., Inland Power& Light, Modern Electric,VERA). kWh
At what point in the analysis does this assumption
get applied?
Chapter 5: Gas Markets and Current Resources
• Page 5-1: Consider expanding on the diminishing Avista considered this, but the eastern
need for gas in the East and the primary factors US and it's gas basins have limited
driving this trend. impact on the Western US as most of
the gas purchases are from Western
Canada. Reduced demand in the
Eastern US would likely lead to reduced
drilling or diversion of natural gas from
the East coast. If supply becomes
constrained due to limited demand,
production would be shut in and reduce
supply to the market while driving costs
downward until a supply/demand
balance is achieved.
• Figures 5.2 & 5.3: Could you replace or supplement All figures are in Nominal dollars. For
these figures with real dollars per dekatherm? the 2027 IRP we would be open to
reporting results in real $.
• Figure 5.4:Additional explanation would be Additional explanation has been added
helpful. to Figure 5.4.
2025 Natural Gas IRP Appendix 21

• Gas Storage Options: For future IRPs, consider Please refer to the Resiliency scenario
analyzing the elevated risk of coincident in the "Alternative Scenarios and
infrastructure failure during peak demand events. Sensitivities and Risks" chapter of the
IRP.
Figure 5.11: What is driving the shape of the The figure appears to show a saturation
voluntary RNG program participation curve? for voluntary RNG based on current
Additionally, how does Avista procure these low program prices, customer desire to
volumes of RNG for participants? participate, and marketing efforts for
the program.These volumes were
historically procured from PSE for the
quantities and volumes needed. Future
volumes will be procured from
contracts secured from Pine Creek.
Chapter 6: Supply-Side Resources
• Figure 6.6: Consider adding Avista's total demand To keep the resources clear we chose
line for reference. not to update in document.
• Figure 6.12: It would be helpful to include gas Because this figure applies to all States
prices plus CCA compliance costs for clarity. Avista believes it best to not include
Consider overlaying the total demand curve to this CCA plus gas line within the supply
contextualize supply costs. costs.
• Figures 6.16-6.21: Adding a narrative discussion on Added to the paragraph to describe the
Avista's acquisition strategy in light of the valuation of these resources in
significant price spread would provide useful comparison to other available
insights. resources and options over time.
Chapter 7: Policy Considerations
• Page 7-7: Consider expanding the discussion of Updated in document
Washington state policy to include information on
the initial 2008 law that established the state's
carbon reduction targets.
• Figure 7.8: Great graph!
• Figure 7.9: Consider adding a sentence explaining Updated in document
the key takeaway from this graph.
• Chapter 7: Consider adding a discussion of ESHB Updated in document
2131 (public policies regarding resource preference
adopted by Washington state, per WAC 480-90-
238(2)(b)).
Chapter 8:Alternate Scenarios
• Presentation of Scenarios: Consider reviewing Updated these figures by breaking out
Northwest Natural's and Cascade's presentation of by state to provide clarity of resource
scenarios—their formatting appears clearer and selections
more intuitive.
• Addressed by Tom's email (3/3/2025): Please Updated to include in Chapter 8
consider adopting at least one scenario where
Avista meets demand per its statutory obligation
while also ensuring compliance with the Climate
Commitment Act in the broader context of
statewide emissions reductions.
2025 Natural Gas IRP Appendix 22

• Figure 8.1: In the high electrification scenario, as See Table 8.9 for price impacts estimate
opposed to the hybrid heating scenario,Staff
anticipates a demand collapse following a 30%
decline in the customer base, primarily due to a 40-
50% increase in fixed costs. Consider providing an
explanation or adjusting the projection to account
for customer responses to rising prices.
• Scenario Forecasts: Will the final version include Figures and descriptions for these
figures for the Diversified Portfolio and Resiliency scenarios are included in Chapter 8
scenarios?
• Figure 8.2:At least for the PRS, it would be useful Updated these figures by breaking out
to have similar graphs broken out by state. by state to provide clarity of resource
selections
• Figure 8.2 (Future IRP Consideration): Consider Thanks for the comment, Avista will
modeling price trends for a fuel that experienced a take that into consideration for future
historical decline in use (e.g., coal or wood IRPs
between the 1940s and 1970s or fuel oil between
the 1960s and 2000s) to compare against projected
gas price trends.
• Figure 8.2: Does the space between the bars and Updated in document to clarify results
the line represent Idaho consumption? Consider
clarifying this and differentiating CCUS and
Alternative Fuels with distinct colors.
• Figures 8.X: Consider changing the way System Updated in document to clarify results
Emissions is displayed—currently,the line format is
unintuitive as it does not visually stack with the
other elements.
• Figures 8.X: It would be helpful to overlay scenarios Avista will consider this in the 2027 IRP
and sensitivities onto the PRS for greater clarity.
• Figure 8.9: Does this scenario include high Updated to include in Chapter 8. All
electrification in Idaho as well? Consider adding a states are included.
note to clarify.
• Page 8-16: Could you elaborate on why there are Avista assumed state and federal
no changes in residential usage in the 1-2066 incentives may help with WA
analysis? residential switchover costs and
customers would continue down the
path of continuing with current building
codes.
• Page 8-18:The IRP describes this as a near worst- This scenario includes high natural gas,
case scenario. Could you elaborate on the alternative fuel prices and high CCA
reasoning?Staff believes a near worst-case would allowance prices. Weather is
include high natural gas and alternative fuel prices, considered warmer than expected to
no 1-2066, cold weather, and high CCA allowance represent less throughput and higher
prices. costs per therm of use with RCP 8.5.
This is in contrast to the RCP 4.5 where
weather is colder and spreads costs
through more demand resulting in a
2025 Natural Gas IRP Appendix 23

lower cost per therm on a total billing
rate. Less HDDs may prove to be a
edge where electrification becomes
more cost effective thus resulting in
less demand on the gas system. _
• Page 8-22: For completeness, consider including I Avista agrees this would be beneficial
information on the total projected/assumed With the possibility of linkage with the
number of allowances per year and the maximum California/Quebec market showing this
allowances projected to be available for Avista per will be considered in the 2027 IRP.
year.
• Figure 8.21:Appears to reflect incorrectly.
• Figures 8.25-8.28: Please specify whether these Avista is open to replacing nominal $
values are in real or nominal dollars. If nominal, with real $ in the 2027 IRP
consider converting to real dollars for consistency.
• Figures 8.25-8.28: Consider adding a discussion in Energy burden has been added for
Chapter 9 about how bill impacts will vary across Oregon and Washington. The full rate
usage levels and income groups, particularly in burden estimate has been added to
hybrid heating and electrification scenarios, per Chapter 8 as well.
WAC 480-90-238(2)(b) ("risks imposed on
ratepayers"). Consider referencing potential
increased burdens on the electric side.
• Figure 8.34: Great graph!
Chapter 9: Customer Equity& Planning Metrics
• Page 9-2: How does Avista see the named Will clarify question and respond to
foundation translating into future planning efforts? staff appropriately
• Page 9-3: Have customer advocates engaged with Yes and the full list of advocates can be
the Technical Advisory Committees (TACs) as found in Chapter 1—Table 1.1
invited?
• Figures 9.3-9.5: Consider replacing these with real- Avista is open to replacing nominal $
dollar values for consistency and accuracy. with real $ in the 2027 IRP
• Figure 9.14: Does this reflect the number of jobs This figure represents the number of jo
created per year? If so, how does this align with creations based on annual energy
the slowdown in energy efficiency growth after efficiency spend as used directly in the
2037? model and aligns directly with figures in
Chapter 3.
2025 Natural Gas IRP Appendix 24

Work Plan for Avista's
2025 Gas Integrated Resource Plan
For the
Technical Advisory Committee,
Washington Utilities and Transportation Commission,
Idaho Public Utility Commission
Updated on March 25, 2024
1
2025 Natural Gas IRP Appendix 25

2025 Gas Integrated Resource Planning (IRP) Work Plan
This work plan, as required in Washington pursuant to Washington Administrative Code (WAC)
480-90-238(4), outlines the process Avista will follow to develop its 2025 Gas IRP, which will be
filed by April 1, 2025. Avista uses a transparent public process to solicit technical expertise and
stakeholder feedback throughout the development of the IRP through a series of Technical
Advisory Committee(TAC)meetings and public outreach to ensure its planning process considers
input from all interested parties prior to Avista's decisions on how to meet future customer gas
needs. All meeting announcements, meeting minutes, meeting recordings, and IRP related
documents and data will be posted on the Company's website at https://www.myavista.com/about-
us/integrated-resource-planning. Avista will communicate with its TAC members through email
and/or Microsoft Teams for any meeting information and data shared outside of TAC meetings,
and all information related to TAC presentations will be provided prior to each TAC meeting.
The 2025 IRP process will use the new modeling techniques referred to as CROME'. Avista is
making this change due to the steadily increasing costs of 3rd party models,which necessitated the
evaluation of alternative modeling options to help contain costs while providing the same level of
analysis and considerations necessary in an IRP.Avista may also use the PRiSM2 model for certain
resource selection options as an alternative to CROME.
Avista contracted with Applied Energy Group (AEG) to assist with key activities including the
energy efficiency and demand response potential studies. AEG will also provide the IRP with a
long-term energy forecast using end use techniques to improve estimates for building and
transportation electrification scenarios. Avista also intends to align the IRP's load forecast and
resource options with this study. The Energy Trust of Oregon (ETO) will continue to provide
results for the Avista Oregon territories and will be directly input into the model as a cost and load
savings.
Avista intends to use both detailed site-specific and generic resource assumptions in the
development of the 2025 IRP. The assumptions will utilize Avista's research of similar gas
producing technologies, engineering studies,vendor estimates and market studies.Avista will rely
on publicly available data to the maximum extent possible and provide its cost and operating
characteristic assumptions and model for review and input by stakeholders. The IRP may model
certain resources as purchase agreements in lieu of Company ownership if it is a lower cost. Future
Requests for Proposals (RFP) will ultimately decide final resource selection and ownership type
based on third party resource options and potential self-build resources specific to Avista's service
territory.
Avista intends to create a Preferred Resource Strategy(PRS)using market and policy assumptions
based on final rules from the Climate Commitment Act (CCA) for Washington. In Oregon, the
Climate Protection Program (CPP) will be included as a scenario as the Department of
' CROME is Avista's proprietary model it uses to select new resources and was developed to replace PLEXOS at a
daily level. CROME is the Comprehensive Resource Optimization Model based in Excel paired with optimization
software.
z PRiSM is Avista's proprietary model it uses to select new resources in the Electric IRP process.Avista first developed
this tool for use in the 2003 IRP.
2
2025 Natural Gas IRP Appendix 26

Environmental Quality moves to re-establish the CPP through rulemaking beginning in Q 12024.
Because the timing and outcome of the CPP rulemaking is unknown, a scenario is the most
appropriate way to consider Oregon's potential future climate policies in the IRP. Conversations
with the TAC as to methods and logic to include in scenarios will be discussed including beginning
the program in 2025 for the PRS. Final CPP rules, that may or may not be the same, will not be
known until after the modeling and process of the 2025 IRP is completed. A similar outcome is
possible with the CCA due to a public initiative to repeal the CCA being submitted to the
Legislature where it can be repealed, altered, or sent to the ballot in the November 2024 election.
In the 2024 legislative session, a bill is being considered to link Washington's program with
California and Quebec's programs, where the CCA program rules would be altered to conform to
the other programs. Finally, a least cost planning methodology will be used in Idaho. For
Washington resource selection, Avista will solve its PRS to include least reasonable cost for
meeting state building codes and energy policies including energy costs, societal externalities such
as Social Cost of Greenhouse Gas, and the non-energy impacts of resource on public health (air
emissions),safety,and economic development.Resource selection will solve for state clean energy
requirements and Avista's energy and capacity planning standards. Avista will track certain
customer metrics the PRS creates to assist in measuring customer equity.
The plan will also include a chapter outlining the key components of the PRS, with a description
of which state policy is driving each resource need. The IRP will include a limited number of
scenarios to address alternative futures in the gas market and public policy, such as limited RNG
and building electrification. TAC meetings help determine the underlying assumptions used in the
IRP,including market scenarios and portfolio studies.Although,Avista will also engage customers
using a public outreach and an informational event, as well as provide transparent information on
the IRP website. The IRP process is technical and data intensive;public comments are encouraged
as timely input and participation ensures inclusion in the process resulting in a resource plan
submitted according to the proposed schedule in this Work Plan.Avista will make all data available
to the public except where it contains market intelligence or proprietary information. The planned
schedule for this data is shown in Exhibit 1. Avista intends to release slides and data five days
prior to its discussion at TAC meetings and expects any comments within two weeks after the
meeting.
The following topics and meeting times may change depending on the availability of presenters
and requests for additional topics from TAC members. The timeline and proposed agenda items
for TAC meetings follows:
• TAC 1:Wed.February 14,2024: 9:00 am to 12:00 pm(PTZ)
• January Peak Event
• Work Plan
• RNG Acquisition
• Customer Impacts
• Modeling Update
• State Policy Update
3
2025 Natural Gas IRP Appendix 27

• Planned Scenarios for Feedback
• TAC 2:Wed.April 24,2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• Action Items from 2023 IRP
• Chosen Model Methodology and modeling overview
• TAC 3:Wed. 15 May 2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• Distribution System Modeling
• Non-Pipe Alternatives(NPA)in Distribution Planning
• Oregon Staff Recommendation on NPA
• TAC 4:Wed.5 June 2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• Future Climate Analysis Update
• Historic weather comparison
• Peak Day Methodology
• TAC 5:Wed.26 June 2024: 10:30 am to 12:00 pm (PTZ)
• Feedback from prior TAC
• GHG assumptions and Climate pricing
• Current natural gas resources
• TAC 6:Wed. 17 July 2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• Load Forecast—AEG
• TAC 7:Wed.7 Aug.2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• Natural Gas Market Overview and Price Forecast
• Avoided Costs Methodology
• TAC 8:Wed.28 Aug.2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• Conservation Potential Assessment(AEG)
• Demand Response Potential Assessment(AEG)
• Conservation Potential Assessment(ETO)
4
2025 Natural Gas IRP Appendix 28

• TAC 9: Wed. 18 Sep.2024: 10:30 am to 12:00 pm(PTZ)
• Feedback from prior TAC
• NEI Study
• New Resource Options Costs and Assumptions
• All assumptions review
• TAC 10:Wed.6 Nov.2024: 9:00 am to 12:00 pm(PTZ)
• Scenario Results
• Scenario Risks
• PRS Overview of selections and risk
• Per Customer Costs by Scenario
• Cost per MTCO2e by Scenario
• Open Questions
• Sep.2024
• Virtual Public Meeting-Natural Gas&Electric IRP
• Recorded presentation
• Daytime comment and question session(12pm to Ipm-PTZ)
• Evening comment and question session(6pm to 7pm-PTZ)
5
2025 Natural Gas IRP Appendix 29

2025 Gas IRP Report Outline
This section provides a draft outline of the expected major sections in the 2025 Gas IRP.
Executive Summary
1. Introduction and Planning Environment
a. Customers
b. Integrated Resource Planning
c. Planning Model
d. Planning Environment
2. Demand Forecasts
a. Demand Areas
b. Customer Forecasts
c. Electrification of Natural Gas Customers
d. Use-per-Customer Forecast
e. Weather Forecast
f. Peak Day Design Temperature
g. Load Forecast
h. Scenario Analysis
i. Alternative Forecasting Methodologies
j. Key Issues
3. Demand Side Resources
a. Avoided Cost
b. Idaho and Washington Conservation Potential Assessment
c. Pursuing Cost-Effective Energy Efficiency
d. Washington and Idaho Energy Efficiency Potential
e. Demand Response
f. Building Electrification
4. Current Resources and New Resource Options
a. Natural Gas Commodity Resources
b. Transportation Resources
c. Storage Resources
d. Incremental Supply-Side Resource Options
e. Alternative Fuel Supply Options
f. Project Evaluation-Build or Buy
g. Avista's Natural Gas Procurement Plan
h. Market-Related Risks and Risk Management
5. Policy Issues
a. Avista's Environmental Objective
b. Natural Gas Greenhouse Gas System Emissions
c. Local Distribution Pipeline Emissions-Methane Study
d. State and Regional Level Policy Considerations
e. Idaho
f. Oregon
g. Washington
h. Federal Legislation
i. Key Takeaways
6. Preferred Resource Strategy
a. Planning Model Overview
b. Stochastic Analysis
6
2025 Natural Gas IRP Appendix 30

c. Resource Integration
d. Carbon Policy Resource Utilization Summary
e. Resource Utilization
f. Demand and Deliverability Balance
g. New Resource Options and Considerations
h. Energy Efficiency Resources
i. Preferred Resource Strategy(PRS)
j. Monte Carlo Risk Analysis
k. Estimated Price Impacts
7. Alternate Scenarios
a. Alternate Demand Scenarios
b. Deterministic—Portfolio Evaluation and Scenario Results
c. Demand
d. PRS Scenarios
e. Electrification Scenarios
f. Supply Scenarios
g. Other Scenarios
h. Washington Climate Commitment Act Allowances
i. Oregon Community Climate Investments
j. Natural Gas Use
k. Methanation
1. Renewable Natural Gas
m. Emissions
n. Cost Comparison
o. Regulatory Requirements
8. Distribution Planning
a. Distribution System Planning
b. Network Design Fundamentals
c. Computer Modeling
d. Determining Peak Demand
e. Distribution System Enhancements
f. Conservation Resources
g. Distribution Scenario Decision-Making Process
h. Planning Results
i. Non-Pipe Alternatives
9. Equity Considerations
a. Overview
b. Equity Metrics
10. Action Plan
a. Avista's 2025 IRP Action Items
b. 2025-2026 Action Plan
7
2025 Natural Gas IRP Appendix 31

Draft IRP will be available to the public on Friday,January 10,2025,and the final draft filed
with Idaho, Oregon, and Washington Commissions on April 1, 2025. Comments from TAC
members are expected back to Avista by Friday, February 7, 2025, or through each states public
comment timeline. Avista's IRP team will be available for conference calls or by email to address
comments with individual TAC members or with the entire group if needed.
•it 1: Major 2025 • •
Task Target Date
CCA/Other GHG Pricing Assumptions June 2024
Due date for study requests from TAC members July 30, 2024
Demand Side Management Deliverables
Final Energy Forecast (AEG) July 2024
Energy Efficiency (AEG & ETO) August 2024
Demand Response (AEG) August 2024
Natural Gas price forecast August 2024
New Resource Options Cost & Availability September 2024
Finalize resource selection model assumptions September 2024
8
2025 Natural Gas IRP Appendix 32

APPENDIX-CHAPTER 1
APPENDIX 1.5: WASHINGTON PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES -WAC 480-90-238
Rule Requirement Plan
Citation
WAC 480-90-238(4) Work plan filed no later than 12 Work plan submitted to the WUTC
months before next IRP due date. on March 26, 2024.
WAC 480-90-238(4) Work plan outlines content of IRP. See Appendix 1.1.
WAC 480-90-238(4) Work plan outlines method for See Appendix 1.1.
assessing potential resources. (See
LRC analysis below
WAC 480-90-238(5) Work plan outlines timing and extent of See Appendix 1.1.
public partici ation.
WAC 480-90-238(4) Integrated resource plan submitted Last Integrated Resource Plan was
within two years of previous plan. submitted on March 31, 2023
WAC 480-90-238(5) Commission issues notice of public TBD
hearing after company files plan for
review.
WAC 480-90-238(5) Commission holds public hearing. TBD
WAC 480-90-238(2)(a) Plan describes mix of natural gas See Chapters 5 and 6 on New and
supply resources. Existing Resources
WAC 480-90-238(2)(a) Plan describes conservation supply. See Chapter 4 on Demand Side
Resources
WAC 480-90-238(2)(a) Plan addresses supply in terms of See Chapter 5 and 6 on New and
current and future needs of utility and Chapter 2 for the Preferred
rate a ers. Resource Selection
WAC 480-90- Plan uses lowest reasonable cost See Chapters 3, 5, and 6 for
238(2)(a)&(b) (LRC)analysis to select mix of Demand and New and Existing
resources. Resources. Chapters 2 and 8
details how Demand and Supply
come together to select the least
cost/best risk portfolio for
ratepa ers.
WAC 480-90-238(2)(b) LRC analysis considers resource See Chapters 3, 5, and 6 for
costs. Demand and New and Existing
Resources. Chapters 2 and 8
details how Demand and Supply
come together to select the least
cost/best risk portfolio for
rate a ers.
WAC 480-90-238(2)(b) LRC analysis considers market- See Chapters 5 and 6 on New and
volatility risks. Existing Resources
WAC 480-90-238(2)(b) LRC analysis considers demand side See Chapter 3 Demand
uncertainties. Forecasting
WAC 480-90-238(2)(b) LRC analysis considers resource See Chapters 3, 5, and 6 for
effect on system operation. Demand and New and Existing
Resources. Chapters 2 and 8
details how Demand and Supply
come together to select the least
cost/best risk portfolio for
ratepa ers.
WAC 480-90-238(2)(b) LRC analysis considers risks See Chapter 5 procurement plan
imposed on ratepayers. section and chapter 8 for risks to
ratepayers and Chapter 2 for the
2025 Natural Gas IRP Appendix 33

APPENDIX-CHAPTER 1
preferred resource selection.
Chapter 7 considers customer
equity and metrics. We seek to
minimize but cannot eliminate
rice risk for our customers.
WAC 480-90-238(2)(b) LRC analysis considers public See Chapter 7 for policies and
policies regarding resource preference chapter 8 for demand scenarios
adopted by Washington state or
federal government.
WAC 480-90-238(2)(b) LRC analysis considers cost of risks See Chapters 2, 3 and 9 on
associated with environmental effects preferred resource selection,
including emissions of carbon dioxide. demand scenarios and customer
equity and metrics
WAC 480-90-238(2)(b) LRC analysis considers need for See Chapters 5 and 6 on Gas
security of supply. Markets and Existing Resources
and Supply Side Resource
Options. Chapter 8 includes
scenarios needs for security of
supply
Rule Requirement Plan Citation
WAC 480-90-238(2)(c) Plan defines conservation as any See Chapter 4 on Demand Side
reduction in natural gas consumption Resources
that results from increases in the
efficienc of energy use or distribution.
WAC 480-90-238(3)(a) Plan includes a range of forecasts of See Chapter 3 on Demand
future demand. Forecast
WAC 480-90-238(3)(a) Plan develops forecasts using See Chapter 3 on Demand
methods that examine the effect of Forecast and chapter 8 for
economic forces on the consumption alternative scenarios and
of natural gas. sensitivities and risks
WAC 480-90-238(3)(a) Plan develops forecasts using See Chapters 3 and 4 on Demand
methods that address changes in the Forecast and Demand Side
number, type and efficiency of natural Resources
as end
-uses.
WAC 480-90-238(3)(b) Plan includes an assessment of See Chapter 4 on Demand Side
commercially available conservation, Management including demand
including load management. response section.
WAC 480-90-238(3)(b) Plan includes an assessment of See Chapters 4 and 5 on Demand
currently employed and new policies Side Resources and Policy
and programs needed to obtain the Considerations and Appendix 4
conservation improvements.
WAC 480-90-238(3)(c) Plan includes an assessment of See Chapter 5 and 6 on New and
conventional and commercially Chapter 2 for the Preferred
available nonconventional gas Resource Selection
supplies.
WAC 480-90-238(3)(d) Plan includes an assessment of See Chapter 5 and 6 on New and
opportunities for using company- Chapter 2 for the Preferred
owned or contracted storage. Resource Selection.
WAC 480-90-238(3)(e) Plan includes an assessment of See Chapters 3, 5, and 6 for
pipeline transmission capability and Demand and New and Existing
reliability and opportunities for Resources. Chapters 2 and 8
additional pipeline transmission details how Demand and Supply
resources. come together to select the least
cost/best risk portfolio for
ratepa ers.
2025 Natural Gas IRP Appendix 34

APPENDIX-CHAPTER 1
WAC 480-90-238(3)(f) Plan includes a comparative evaluation See Chapter 4 on Demand Side
of the cost of natural gas purchasing Resources and Chapters 3, 5, and
strategies, storage options, delivery 6 for Demand and New and
resources, and improvements in Existing Resources. Chapters 2
conservation using a consistent and 8 details how Demand and
method to calculate cost-effectiveness. Supply come together to select the
least cost/best risk portfolio for
rate a ers.
WAC 480-90-238(3)(g) Plan includes at least a 10 year long- Our plan is a comprehensive 20
range planning horizon. year plan. (2026-2045)
WAC 480-90-238(3)(g) Demand forecasts and resource See Chapter 4 on Demand Side
evaluations are integrated into the long Resources and Chapters 3, 5, and
range plan for resource acquisition. 6 for Demand and New and
Existing Resources. Chapters 2
and 8 details how Demand and
Supply come together to select the
least cost/best risk portfolio for
ratepa ers.
WAC 480-90-238(3)(h) Plan includes a two-year action plan See Section 11 Action Plan
that implements the long range plan.
WAC 480-90-238(3)(i) Plan includes a progress report on the See Section 11 Action Plan
implementation of the previously filed
Ian.
WAC 480-90-238(5) Plan includes description of See Appendix 1.1
consultation with commission staff.
Description not required)
WAC 480-90-238(5) Plan includes description of completion See Appendix 1.1.
of work plan. (Description not required)
2025 Natural Gas IRP Appendix 35

APPENDIX-CHAPTER 1
APPENDIX 1.2: IDAHO PUBLIC UTILITY COMMISSION IRP POLICIES AND
GUIDELINES - ORDER NO. 2534
DESCRIPTION OF REQUIREMENT FULLFILLMENT OF REQUIREMENT
1 Purpose and Process. Each gas utility regulated by Avista prepares a comprehensive 20 year
the Idaho Public Utilities Commission with retail Integrated Resource Plan every two years.
sales of more than 10,000,000,000 cubic feet in a Avista will be filing its 2025 IRP on or before
calendar year (except gas utilities doing business April 1, 2025.
in Idaho that are regulated by contract with a
regulatory commission of another State) has the
responsibility to meet system demand at least cost
to the utility and its ratepayers. Therefore, an
"integrated resource plan" shall be developed by
each gas utility subject to this rule.
2 Definition. Integrated resource planning. See Chapter 4 on Demand Side Resources
"Integrated resource planning" means planning by and Chapters 3, 5, and 6 for Demand and
the use of any standard, regulation, practice, or New and Existing Resources. Chapters 2
policy to undertake a systematic comparison and 8 details how Demand and Supply come
between demand-side management measures and together to select the least cost/best risk
the supply of gas by a gas utility to minimize life- portfolio for ratepayers.
cycle costs of adequate and reliable utility services
to gas customers. Integrated resource planning
shall take into account necessary features for
system operation such as diversity, reliability,
dispatchability, and other factors of risk and shall
treat demand and supply to gas consumers on a
consistent and integrated basis.
3 Elements of Plan. Each gas utility shall submit to The last IRP was filed on March 31, 2023.
the Commission on a biennial basis an integrated
resource plan that shall include:
A range of forecasts of future gas demand in firm See Chapter 4 on Demand Side Resources
and interruptible markets for each customer class and Chapters 3, 5, and 6 for Demand and
for one, five, and twenty years using methods that New and Existing Resources. Chapters 2
examine the effect of economic forces on the and 8 details how Demand and Supply come
consumption of gas and that address changes in together to select the least cost/best risk
the number, type and efficiency of gas end-uses. portfolio for ratepayers.
An assessment for each customer class of the See Chapter 4 - Demand Side
technically feasible improvements in the efficient Management and DSM Appendices 4 et.al.
use of gas, including load management, as well as for detailed information on the DSM potential
the policies and programs needed to obtain the evaluated and selected for this IRP and the
efficiency improvements. operational implementation process.
2025 Natural Gas IRP Appendix 36

APPENDIX-CHAPTER 1
An analysis for each customer class of gas supply See Chapters 5 and 6 for details about the
options, including: (1) a projection of spot market market, storage, and pipeline transportation
versus long-term purchases for both firm and as well as other resource options considered
interruptible markets; (2) an evaluation of the in this IRP. See also the procurement plan
opportunities for using company-owned or section in chapter 5 for supply procurement
contracted storage or production; (3) an analysis of strategies.
prospects for company participation in a gas futures
market; and (4) an assessment of opportunities for
access to multiple pipeline suppliers or direct
purchases from producers.
A comparative evaluation of gas purchasing See Methodology section of Chapter 3 -
options and improvements in the efficient use of Demand-Side Resources where we
gas based on a consistent method for calculating describe our process on how demand-side
cost-effectiveness. and New and Existing Resources are
compared on par with each other in the
CROME model. Chapter 4 also includes how
results from the IRP are then utilized to
create operational business plans.
Operational implementation may differ from
IRP results due to modeling assumptions.
The integration of the demand forecast and See Chapter 2— Preferred Resource
resource evaluations into a long-range (e.g., Selection and Chapter 8 Alternative
twenty-year) integrated resource plan describing Scenarios and Sensitivities and Risks for
the strategies designed to meet current and future details on how we model demand and supply
needs at the lowest cost to the utility and its coming together to provide the least cost/best
ratepayers. risk portfolio of resources in comparison to
alternative futures and resource options.
A short-term (e.g., two-year) plan outlining the See Chapter 11 -Action Plan for actions to
specific actions to be taken by the utility in be taken in implementing the IRP.
implementing the integrated resource plan.
4 Relationship Between Plans. All plans following the See Chapter 11 -Action Plan
initial integrated resource plan shall include a
progress report that relates the new plan to the
previously filed plan.
rJ Plans to Be Considered in Rate Cases. The We prepare and file our plan in part to
integrated resource plan will be considered with establish a public record of our plan.
other available information to evaluate the
performance of the utility in rate proceedings before
the Commission.
6 Public Participation. In formulating its plan, the gas Avista held 11 Technical Advisory Committee
utility must provide an opportunity for public meetings beginning in February and ending
participation and comment and must provide in December. A public focused meeting
methods that will be available to the public of occurred on March 5, 2025. See Chapter 1 -
validating predicted performance. Introduction for more detail about public
participation in the IRP process.
2025 Natural Gas IRP Appendix 37

APPENDIX-CHAPTER 1
7 Legal Effect of Plan. The plan constitutes the base See section titled "Avista's Natural Gas
line against which the utility's performance will Procurement Plan" in Chapter 5—Gas
ordinarily be measured. The requirement for Markets and Existing Resources. Among
implementation of a plan does not mean that the other details we discuss plan revisions in
plan must be followed without deviation. The response to changing market conditions.
requirement of implementation of a plan means that
a gas utility, having made an integrated resource
plan to provide adequate and reliable service to its
gas customers at the lowest system cost, may and
should deviate from that plan when presented with
responsible, reliable opportunities to further lower
its planned system cost not anticipated or identified
in existing or earlier plans and not undermining the
utility's reliability.
$ In order to encourage prudent planning and prudent See also section titled "Alternate Scenarios
deviation from past planning when presented with and Sensitivities and Risks" in Chapter 8 for
opportunities for improving upon a plan, a gas a comparison to all future scenarios
utility's plan must be on file with the Commission considered in the 2025 IRP.
and available for public inspection. But the filing of
a plan does not constitute approval or disapproval
of the plan having the force and effect of law, and
deviation from the plan would not constitute
violation of the Commission's Orders or rules. The
prudence of a utility's plan and the utility's prudence
in following or not following a plan are matters that
may be considered in a general rate proceeding or
other proceedings in which those issues have been
noticed.
2025 Natural Gas IRP Appendix 38

APPENDIX-CHAPTER 1
APPENDIX 1.2: OREGON PUBLIC UTILITY COMMISSION IRP STANDARD AND
GUIDELINES - ORDER 07- 002
Guideline 1: Substantive Requirements
1.a.1 All resources must be evaluated on a consistent and All resource options considered,
comparable basis. including demand-side and
supply-side are modeled in
CROME utilizing the same
common general assumptions,
a roach, and methodology.
1.a.2 All known resources for meeting the utility's load should Avista considered a range of
be considered, including supply-side options which focus resources including demand-side
on the generation, purchase and transmission of power— management, distribution system
or gas purchases, transportation, and storage—and enhancements, capacity release
demand-side options which focus on conservation and recalls, interstate pipeline
demand response. transportation, interruptible
customer supply, renewable
natural gas by source, hydrogen,
electrification by end source and
synthetic methane. Chapter 4
and Appendix 4.1 documents
Avista's demand-side
management resources
considered. Chapters 5 and 6
show New and Existing
Resources. Chapter 2 and 8
documents how Avista developed
and assessed each of these
resources.
1.a.3 Utilities should compare different resource fuel types, Avista considered various
technologies, lead times, in-service dates, durations and combinations of technologies,
locations in portfolio risk modeling. lead times, in-service dates,
durations, and locations. Chapter
2 provides details about the
modeling methodology and
results. Chapter 5 describes
current resource options and
Chapter 6 describes new
resource options and lead times.
1.a.4 Consistent assumptions and methods should be used for Appendix 6.2 documents general
evaluation of all resources. assumptions used in Avista's
CROME modeling software. All
portfolio resources both demand
and supply-side were evaluated
within CROME using the same
sets of in uts.
1.a.5 The after-tax marginal weighted-average cost of capital See Appendix 0
(WACC) should be used to discount all future resource
costs.
1.b.1 Risk and uncertainty must be considered. Electric utilities Risk and uncertainty can be
only found in Chapter 6 and Chapter
8.
2025 Natural Gas IRP Appendix 39

APPENDIX-CHAPTER 1
1.b.2 Risk and uncertainty must be considered. Natural gas See Chapter 4 on Demand Side
utilities should consider demand (peak, swing and base- Resources and Chapters 3, 5,
load), commodity supply and price, transportation and 6 for Demand and New and
availability and price, and costs to comply with any Existing Resources. Chapters 2
regulation of greenhouse gas (GHG) emissions. and 8 details how Demand and
Supply come together to select
the least cost/best risk portfolio
for ratepa ers.
Utilities should identify in their plans any additional See Chapter 4 on Demand Side
sources of risk and uncertainty. Resources and Chapters 3, 5,
and 6 for Demand and New and
Existing Resources. Chapters 2
and 8 details how Demand and
Supply come together to select
the least cost/best risk portfolio
for ratepa ers.
1c The primary goal must be the selection of a portfolio of Avista evaluated cost/risk
resources with the best combination of expected costs tradeoffs for each of the risk
and associated risks and uncertainties for the utility and analysis portfolios considered.
its customers. See Chapter 2 and 8 plus
supporting information in the
Appendix.
The planning horizon for analyzing resource choices Avista used a 20-year study
should be at least 20 years and account for end effects. period for portfolio modeling.
Utilities should consider all costs with a reasonable Avista contemplated possible
likelihood of being included in rates over the long term, costs beyond the planning period
which extends beyond the planning horizon and the life that could affect rates including
of the resource. end effects such as infrastructure
decommission costs and
concluded there were no
significant costs reasonably likely
to impact rates under different
resource selection scenarios.
Utilities should use present value of revenue requirement Avista's CROME modeling
(PVRR) as the key cost metric. The plan should include software utilizes a PVRR cost
analysis of current and estimated future costs of all long- metric methodology applied to
lived resources such as power plants, gas storage both long and short-lived
facilities and pipelines, as well as all short-lived resources.
resources such as gas supply and short-term power
purchases.
To address risk, the plan should include at a minimum: 1) Avista, through its stochastic
Two measures of PVRR risk: one that measures the analysis, modeled 500 twenty
variability of costs and one that measures the severity of year futures via Monte Carlo
bad outcomes. 2) Discussion of the proposed use and iterations developing a
impact on costs and risks of physical and financial distribution of total 20 year cost
hedging. estimates utilizing CROME PVRR
methodology. Chapter 5
discusses Avista's physical and
financial hedging methodology.
Chapter 8 discusses risk and
severity of bad outcomes.
The utility should explain in its plan how its resource Chapter 2 to 10 describe various
choices appropriately balance cost and risk. specific resource considerations
and related risks.
2025 Natural Gas IRP Appendix 40

APPENDIX-CHAPTER 1
1d The plan must be consistent with the long-run public Avista considered state and
interest as expressed in Oregon and federal energy federal energy policies and
policies. impacts as described in Chapter
7.
Guideline 2: Procedural Requirements
2a The public, including other utilities, should be allowed Chapter 1 provides an overview
significant involvement in the preparation of the IRP. of the public process and
Involvement includes opportunities to contribute documents the details on public
information and ideas, as well as to receive information. meetings held for the 2025 IRP.
Parties must have an opportunity to make relevant Avista encourages participation in
inquiries of the utility formulating the plan. the development of the plan, as
each party brings a unique
perspective and the ability to
exchange information and ideas
makes for a more robust plan.
While confidential information must be protected, the The entire IRP, as well as the
utility should make public, in its plan, any non- TAC process, and website
confidential information that is relevant to its resource includes all of the non-
evaluation and action plan. confidential information the
company used for portfolio
evaluation and selection. Avista
also provided stakeholders with
non-confidential information to
support public meeting
discussions via email. The
document and appendices will be
available on the company
website for viewing.
The utility must provide a draft IRP for public review and Avista distributed a draft IRP
comment prior to filing a final plan with the Commission. document for external review to
all TAC members from January
31, 2025 to February 21, 2025
and requested comments by
March 7, 2025. All comments
and responses are included in
Appendix 1
Guideline 3: Plan Filing, Review and Updates
3a Utility must file an IRP within two years of its previous The 2023 IRP was filed March
IRP acknowledgement order. 31, 2023 with short term
acknowledgement in May of
2024. The 2025 IRP will be filed
on or before March 31, 2025.
3b Utility must present the results of its filed plan to the Avista will work with Staff to fulfill
Commission at a public meeting prior to the deadline for this guideline following filing of
written public comment. the IRP.
3c Commission staff and parties should complete their Pending
comments and recommendations within six months of
IRP filing
3d The Commission will consider comments and Pending
recommendations on a utility's plan at a public meeting
before issuing an order on acknowledgment. The
Commission may provide the utility an opportunity to
revise the plan before issuing an acknowledgment order
2025 Natural Gas IRP Appendix 41

APPENDIX-CHAPTER 1
3e The Commission may provide direction to a utility Pending
regarding any additional analyses or actions that the
utility should undertake in its next IRP.
3f Each utility must submit an annual update on its most The 2025 IRP will be filed in full
recently acknowledged plan. The update is due on or with the OPUC as an extension
before the acknowledgment order anniversary date. was granted to issue an
Once a utility anticipates a significant deviation from its extension from May 2026 to April
acknowledged IRP, it must file an update with the 1, 2027 due to the RAC process
Commission, unless the utility is within six months of for developing new rules for the
filing its next IRP. The utility must summarize the update CPP.
at a Commission public meeting. The utility may request
acknowledgment of changes in proposed actions
identified in an update
3g Unless the utility requests acknowledgement of changes Avista will utilized the updated
in proposed actions, the annual update is an IRP template to discuss changes
informational filing that: with the Commission at our
II Describes what actions the utility has taken to annual update around May 2025.
implement the plan;
II Provides an assessment of what has changed since
the acknowledgment order that affects the action plan,
including changes in such factors as load, expiration of
resource contracts, supply-side and demand-side
resource acquisitions, resource costs, and
transmission availability; and
II Justifies any deviations from the acknowledged action
Ian.
Guideline 4: Plan Components
At a minimum, the plan must include the following
elements:
4a An explanation of how the utility met each of the This table summarizes guideline
substantive and procedural requirements. compliance by providing an
overview of how Avista met each
of the substantive and procedural
requirements for a natural gas
IRP.
4b Analysis of high and low load growth scenarios in Chapter 3 describes the demand
addition to stochastic load risk analysis with an forecast data and risk analysis of
explanation of major assumptions. demand. Chapter 5 and 6
describes price risk. Chapter 8
provides the scenario and
sensitivities and risk analysis
results.
4c For electric utilities only Not Applicable
4d A determination of the peaking, swing and base-load gas Chapter 2 describes peak
supply and associated transportation and storage demand expectations and
expected for each year of the plan, given existing preferred resource selection.
resources; and identification of gas supplies (peak, swing
and base-load), transportation and storage needed to
bridge the gap between expected loads and resources.
4e Identification and estimated costs of all supply-side and Chapter 4 and Appendix 4.1
demand-side resource options, taking into account identify the demand-side potential
anticipated advances in technology included in this IRP. Chapter 4, 5
&6 and Appendix 6.3 identify the
New and Existing Resources.
4f Analysis of measures the utility intends to take to provide Chapter 2 discusses analysis of
reliable service, including cost-risk tradeoffs. the preferred resource selection.
2025 Natural Gas IRP Appendix 42

APPENDIX-CHAPTER 1
Chapter 8 shows the distribution
or city gate upgrades that may
need to occur to provide reliability
and cost-risk tradeoffs. Chapter
9 shows the energy burden
expected from these choices for
residential customers.
4g Identification of key assumptions about the future (e.g. Chapter 5,6, and 7 identifies
fuel prices and environmental compliance costs) and assumptions about future costs
alternative scenarios considered. or prices and the polices driving
these costs while chapter 8
considers alternative scenarios
and future cost variability.
4h Construction of a representative set of resource This Plan documents the
portfolios to test various operating characteristics, development and results for
resource types, fuels and sources, technologies, lead portfolios evaluated in chapters 2
times, in-service dates, durations and general locations - and 8.
system-wide or delivered to a specific portion of the
system.
4i Evaluation of the performance of the candidate portfolios We evaluated our candidate
over the range of identified risks and uncertainties. portfolio by performing stochastic
analysis using CROME varying
price, volumetric availability of
alternative fuels and weather
under 500 different scenarios.
Additionally, we test the portfolio
of options with the use of
CROME under deterministic
scenarios where demand and
rice vary.
4j Results of testing and rank ordering of the portfolios by Chapter 8 illustrates cost and risk
cost and risk metric, and interpretation of those results. variability of the 19 modeled
scenarios in the 2025 IRP.
4k Analysis of the uncertainties associated with each See the responses to 1.b above.
portfolio evaluated
41 Selection of a portfolio that represents the best Avista evaluated cost/risk
combination of cost and risk for the utility and its tradeoffs for each of the risk
customers analysis in Cha ter 8.
4m Identification and explanation of any inconsistencies of This IRP is presumed to have no
the selected portfolio with any state and federal energy inconsistencies.
policies that may affect a utility's plan and any barriers to
implementation
4n An action plan with resource activities the utility intends The action plan and resource
to undertake over the next two to four years to acquire needs and selection can be found
the identified resources, regardless of whether the in Chapter 11.
activity was acknowledged in a previous IRP, with the
key attributes of each resource specified as in portfolio
testing.
Guideline 5: Transmission
5 Portfolio analysis should include costs to the utility for the Chapters 5, 6 and 8 consider all
fuel transportation and electric transmission required for resource options available and
each resource being considered. In addition, utilities their selections in each
should consider fuel transportation and electric scenario/sensitivity.
transmission facilities as resource options, taking into
account their value for making additional purchases and
2025 Natural Gas IRP Appendix 43

APPENDIX-CHAPTER 1
sales, accessing less costly resources in remote
locations, acquiring alternative fuel supplies, and
improving reliability.
Guideline 6: Conservation
6a Each utility should ensure that a conservation potential ETO and AEG both performed a
study is conducted periodically for its entire service conservation potential
territory. assessment study for our 2025
IRP. A discussion of the study is
included in Chapter 4. Each full
study document is in Appendix
4.1. Avista incorporates a
comprehensive assessment of
the potential for utility acquisition
of energy-efficiency resources
into the regularly-scheduled
Integrated Resource Planning
process.
6b To the extent that a utility controls the level of funding for Chapter 11 contains the
conservation programs in its service territory, the utility requested information.
should include in its action plan all best cost/risk portfolio
conservation resources for meeting projected resource
needs, specifying annual savings targets.
6c To the extent that an outside party administers See the response for 6.b above.
conservation programs in a utility's service territory at a ETO administers all programs in
level of funding that is beyond the utility's control, the Oregon other than low-income
utility should: 1) determine the amount of conservation residential. These conservation
resources in the best cost/ risk portfolio without regard to resources are discussed in depth
any limits on funding of conservation programs; and 2) in Chapter 4, pairing these results
identify the preferred portfolio and action plan consistent with the preferred resource
with the outside party's projection of conservation selection in Chapter 2. These
acquisition. CPAs can be found in Appendix 4
b potential study.
Guideline 7: Demand Response
7 Plans should evaluate demand response resources, Avista has periodically evaluated
including voluntary rate programs, on par with other conceptual approaches to
options for meeting energy, capacity, and transmission meeting capacity constraints
needs (for electric utilities)or gas supply and using demand-response and
transportation needs (for natural gas utilities). similar voluntary programs.
Technology, customer
characteristics and cost issues
are hurdles for developing
effective pro rams.
Guideline 8: Environmental Costs
8 Utilities should include, in their base-case analyses, the These costs can be found in
regulatory compliance costs they expect for CO2, NOx, Chapter 9 and are also discussed
SO2, and Hg emissions. Utilities should analyze the in Chapter 7. The Environmental
range of potential CO2 regulatory costs in Order No. 93- Externalities discussion in
695, from $0-$40 (1990$). In addition, utilities should Appendix 9.2 describes our
perform sensitivity analysis on a range of reasonably analysis performed. Sensitivities
possible cost adders for NOx, SO2, and Hg, if applicable. to these costs can be found in
Chapter 8.
Guideline 9: Direct Access Loads
2025 Natural Gas IRP Appendix 44

APPENDIX-CHAPTER 1
9 An electric utility's load-resource balance should exclude Not applicable to Avista's gas
customer loads that are effectively committed to service utility operations.
by an alternative electricity supplier.
Guideline 10: Multi-state utilities
10 Multi-state utilities should plan their generation and The 2025 IRP conforms to the
transmission systems, or gas supply and delivery, on an multi-state planning approach
integrated-system basis that achieves a best cost/risk with a specific cost of compliance
portfolio for all their retail customers. to Oregon and Washington for
their respective climate
compliance programs as
discussed throughout the IRP.
Guideline 11: Reliability
11 Electric utilities should analyze reliability within the risk This demonstration of these
modeling of the actual portfolios being considered. Loss guidelines can be found in
of load probability, expected planning reserve margin, Chapters 2, 4, 5, 6, 7 and 8
and expected and worst-case unserved energy should where all resources and policies
be determined by year for top-performing portfolios. considered in chapters 4 to 7 are
Natural gas utilities should analyze, on an integrated modeled for a optimal solution in
basis, gas supply, transportation, and storage, along with chapter 2 and risk in 8.
demand-side resources, to reliably meet peak, swing,
and base-load system requirements. Electric and natural
gas utility plans should demonstrate that the utility's
chosen portfolio achieves its stated reliability, cost and
risk objectives.
Guideline 12: Distributed Generation
12 Electric utilities should evaluate distributed Not applicable to Avista's gas
generation technologies on par with other New and utility operations.
Existing Resources and should consider, and quantify
where possible, the additional benefits of distributed
generation.
Guideline 13: Resource Acquisition
13a An electric utility should: identify its proposed acquisition Avista will release an annual RFP
strategy for each resource in its action plan; Assess the to determine least cost solutions
advantages and disadvantages of owning a resource and continually monitor loads for
instead of purchasing power from another party; identify possible shifts in expected
any Benchmark Resources it plans to consider in demand. Chapter 11 shows the
competitive bidding. resources selected in the PRS
scenario for the 2025 IRP.
13b Natural gas utilities should either describe in the IRP A discussion of Avista's
their bidding practices for gas supply and transportation, procurement practices is detailed
or provide a description of those practices following IRP in Chapter 5.
acknowledgment.
Guideline 8: Environmental Costs
a. BASE CASE AND OTHER COMPLIANCE SCENARIOS: Chapter 2 is considered the base
The utility should construct a base-case scenario to case with the preferred resource
reflect what it considers to be the most likely regulatory selections of options modeled
compliance future for carbon dioxide (CO2), nitrogen within the 2025 IRP. Chapter 8
oxides, sulfur oxides, and mercury emissions. The utility considers alternatives using a
also should develop several compliance scenarios variety of compliance methods for
ranging from the present CO2 regulatory level to the weather futures, upstream
upper reaches of credible proposals by governingemissions and SCC.
2025 Natural Gas IRP Appendix 45

APPENDIX-CHAPTER 1
entities. Each compliance scenario should include a time
profile of CO2 compliance requirements. The utility
should identify whether the basis of those requirements,
or"costs", would be CO2 taxes, a ban on certain types of
resources, or CO2 caps (with or without flexibility
mechanisms such as allowance or credit trading or a
safety valve). The analysis should recognize significant
and important upstream emissions that would likely have
a significant impact on its resource decisions. Each
compliance scenario should maintain logical consistency,
to the extent practicable, between the CO2 regulatory
requirements and other key inputs.
b. TESTING ALTERNATIVE PORTFOLIOS AGAINST THE Chapter 2 contains the PRS,
COMPLIANCE SCENARIOS: The utility should Chapter 8 contains alternative
estimate, under each of the compliance scenarios, the scenarios and portfolio analysis
present value of revenue requirement (PVRR) costs and for the PRS and cost
risk measures, over at least 20 years, for a set of implications. Chapter 9
reasonable alternative portfolios from which the preferred considers energy burden from
portfolio is selected. The utility should incorporate end- these selections in the PRS to
effect considerations in the analyses to allow for income levels and induced
comparisons of portfolios containing resources with benefits to the state economy
economic or physical lives that extend beyond the with resources selected and
planning period. The utility should also modify projected emissions.
lifetimes as necessary to be consistent with the
compliance scenario under analysis. In addition, the
utility should include, if material, sensitivity analyses on a
range of reasonably possible regulatory futures for
nitrogen oxides, sulfur oxides, and mercury to further
inform the preferred portfolio selection.
2025 Natural Gas IRP Appendix 46

WINTER AVOIDED COST PER DEKATHERM (NOMINAL $)
2025/2026 and 2045/2046 values reflect only the first three and last two months of
the year, respectively.
Residential Customers
Average Case
Winter iversified Portfolio High Alternative Fuel
Costs
0-01§WA ID OR WA ID • '
- 4 - ID
2025/2026 4.27 3.35 5.00 4.31 3.38 4.62 4.31 3.38 4.63
2026/2027 4.57 3.73 6.07 4.64 3.94 5.65 4.65 3.94 5.65
2027/2028 4.98 3.86 6.42 5.02 4.08 5.80 5.03 4.08 5.81
2028/2029 5.19 3.94 6.86 5.20 4.16 5.99 5.21 4.16 6.12
2029/2030 5.38 4.01 7.03 5.35 4.03 9.38 5.37 4.03 6.55
2030/2031 5.73 3.99 7.72 9.47 4.00 7.49 5.66 4.00 7.12
2031/2032 6.38 4.14 8.09 10.61 4.15 9.07 6.35 4.15 7.64
2032/2033 6.59 4.44 8.92 10.11 4.45 10.81 6.44 4.45 8.41
2033/2034 6.99 4.62 9.34 10.33 4.64 12.32 6.90 4.64 9.08
2034/2035 7.24 4.78 9.72 10.85 4.79 12.41 7.03 4.79 9.63
2035/2036 7.55 4.87 10.07 10.20 4.90 13.91 7.46 4.89 9.91
2036/2037 7.77 5.05 10.49 11.14 5.08 13.85 7.56 5.08 10.00
2037/2038 7.77 5.21 10.69 11.84 5.23 14.49 7.52 5.23 10.42
2038/2039 8.08 5.40 10.92 10.64 5.43 16.31 7.86 5.43 10.86
2039/2040 8.35 5.61 11 .29 11.12 5.65 15.09 7.90 5.64 11.04
2040/2041 8.64 5.86 11.82 11.18 5.91 16.13 8.08 5.91 11.55
2041/2042 8.94 6.05 12.14 11.15 6.09 15.90 8.54 6.09 11.84
2042/2043 9.26 6.20 12.55 10.86 6.25 16.82 8.86 6.24 12.26
2043/2044 9.62 6.41 12.97 10.64 6.44 16.90 9.15 6.44 12.66
2044/2045 10.13 6.65 13.32 11.57 6.68 16.88 9.43 6.68 12.54
2045/2046 11.24 7.03 13.63 12.56 6.83 16.86 10.35 6.83 12.57
Pricingr Winter High CCA Allowance High Electrification High Growth on the
11'r Gas System
WA ID • ' WA ID • ' WA IDR
2025/2026 4.50 3.38 4.63 4.35 3.43 4.63 4.31 -T3-67 4.47
2026/2027 4.86 3.94 5.65 4.71 4.03 5.65 4.68 3.92 5.57
2027/2028 5.30 4.08 5.81 7.35 5.57 5.83 5.08 4.06 5.86
2028/2029 5.51 4.16 6.12 9.71 7.00 6.06 5.27 4.14 6.30
2029/2030 5.70 4.03 6.49 10.75 8.46 6.44 5.45 4.02 6.48
2030/2031 6.06 4.00 7.00 12.79 9.57 6.28 5.75 3.99 7.10
2031/2032 6.88 4.15 7.51 16.13 11 .20 6.64 6.34 4.14 7.68
2032/2033 7.01 4.45 8.37 18.69 13.21 7.61 6.56 4.44 8.55
2033/2034 7.42 4.64 8.85 22.24 15.11 7.80 6.93 4.62 9.16
2034/2035 7.56 4.79 9.28 24.87 17.21 8.65 7.19 4.78 9.62
Avista Corp 2025 Gas IRP DRAFT 1
2025 Natural Gas IRP Appendix 47

2035/2036 8.11 4.90 9.68 31.05 23.66 8.78 7.48 4.88 9.95
2036/2037 8.35 5.08 9.82 37.56 29.44 9.03 7.70 5.06 10.32
2037/2038 8.12 5.23 10.27 45.19 33.55 9.35 7.61 5.22 10.55
2038/2039 8.41 5.43 10.62 55.55 41.89 9.61 7.89 5.41 10.92
2039/2040 9.09 5.65 10.61 69.69 53.62 9.22 8.20 5.62 11.30
2040/2041 9.44 5.91 11.08 86.93 73.42 9.30 8.32 5.88 11.85
2041/2042 9.25 6.10 11.34 149.63 99.67 9.85 8.68 6.07 12.29
2042/2043 9.61 6.24 11.43 227.42 133.24 9.65 8.98 6.21 12.37
2043/2044 10.07 6.45 11.89 291.63 174.65 10.43 9.33 6.42 12.93
2044/2045 10.36 6.68 11.96 389.56 220.80 9.24 9.63 6.66 13.41
2045/2046 11.92 6.83 11.82 445.25 242.91 8.83 10.88 6.83 13.66
iff
2025/2026 4.60 3.57 4.83 4.31 3.38 4.63 4.31 3.38 4.63
2026/2027 5.61 4.76 6.64 4.65 3.94 5.65 4.68 3.94 5.65
2027/2028 6.60 5.35 7.25 5.70 6.85 5.81 5.07 4.08 5.81
2028/2029 7.20 5.83 8.00 7.41 7.53 6.08 5.28 4.16 6.12
2029/2030 7.68 6.15 8.47 8.58 6.84 6.39 5.46 4.03 6.49
2030/2031 8.18 6.18 9.06 9.29 7.49 6.79 5.77 4.00 7.06
2031/2032 9.63 6.58 9.13 10.26 8.57 7.55 6.36 4.15 7.39
2032/2033 9.79 7.54 11 .12 10.88 9.54 7.72 6.58 4.45 8.21
2033/2034 10.76 7.84 11.60 11 .98 10.31 8.28 6.97 4.64 8.61
2034/2035 11.17 8.61 11.98 12.55 11.30 8.77 7.26 4.79 9.10
2035/2036 11.63 8.79 12.51 14.80 12.93 9.04 7.53 4.90 9.35
2036/2037 11.99 9.21 12.52 16.35 14.77 9.25 7.76 5.08 9.58
2037/2038 12.37 9.65 13.35 16.48 17.74 9.60 7.70 5.23 9.92
2038/2039 13.89 10.08 13.39 18.35 19.48 9.96 8.02 5.43 10.33
2039/2040 13.68 11 .12 13.99 21.55 18.29 10.05 8.30 5.64 10.47
2040/2041 14.38 11 .63 14.55 23.86 18.63 10.35 8.63 5.91 10.87
2041/2042 14.18 11 .51 14.38 26.76 19.98 10.71 8.81 6.09 11 .10
2042/2043 15.11 11 .70 14.62 29.81 21.33 10.69 9.11 6.24 11 .21
2043/2044 16.27 12.63 15.39 31.29 24.75 11.13 9.46 6.44 11 .58
2044/2045 15.66 13.44 14.89 37.01 25.06 11.69 9.76 6.68 12.09
2045/2046 17.02 13.45 15.18 41.07 24.21 11.62 11 .03 6.83 12.11
PurchasedAlternative Fuel Low Natural Gas Use No
A-MW OF�IMP IDAL OR JjWVA ._j&_ OR�
Costs Allowances After
2025/2026 4.31 3.38 4.63 4.80 3.60 4.86 4.32 3.38 4.63
2026/2027 4.65 3.94 5.65 5.84 4.75 6.67 4.65 3.94 5.65
Avista Corp 2025 Gas IRP DRAFT 2
2025 Natural Gas IRP Appendix 48

2027/2028 5.03 4.08 5.81 6.91 5.36 7.26 5.03 4.08 5.81
2028/2029 5.21 4.16 6.12 7.54 5.84 7.94 5.22 4.16 6.12
2029/2030 5.37 4.03 6.45 8.02 6.17 8.65 5.39 4.03 7.77
2030/2031 5.66 4.00 6.87 8.98 6.20 9.17 8.06 4.00 8.25
2031/2032 6.35 4.15 7.07 10.43 6.60 9.59 11 .90 4.15 7.09
2032/2033 6.44 4.45 7.90 10.62 7.57 11.27 13.98 4.45 8.45
2033/2034 6.91 4.64 8.30 11.47 7.87 11.41 13.09 4.64 9.14
2034/2035 7.03 4.79 8.67 11.83 8.65 12.53 14.56 4.79 10.55
2035/2036 7.46 4.89 8.95 12.40 8.84 13.12 13.69 4.89 12.77
2036/2037 7.60 5.08 9.29 13.21 9.27 13.15 14.30 5.08 12.85
2037/2038 7.52 5.23 9.54 13.16 9.68 13.79 14.15 5.23 13.66
2038/2039 7.78 5.43 9.99 14.78 10.16 14.00 14.75 5.43 13.45
2039/2040 8.03 5.64 10.20 14.69 11.10 14.90 14.34 5.65 15.16
2040/2041 8.28 5.91 10.42 15.46 11.70 15.24 14.13 5.91 15.92
2041/2042 8.55 6.09 10.83 15.12 11.57 15.12 14.74 6.09 15.69
2042/2043 8.87 6.24 10.78 16.35 11.73 15.56 15.31 6.24 16.24
2043/2044 9.15 6.45 11.29 17.43 12.61 16.60 16.36 6.44 15.86
2044/2045 9.43 6.68 11.64 16.51 13.07 15.81 15.32 6.68 16.88
2045/2046 10.35 6.83 11.87 18.45 13.36 16.04 14.01 6.83 14.22
► . -
1 • -J
2025/2026 3.68 3.38 4.63 4.31 3.38 4.63 4.32 3.38 4.63
2026/2027 3.94 3.94 5.54 4.62 3.94 5.66 4.64 3.94 5.65
2027/2028 4.15 4.08 5.67 4.98 4.08 5.83 5.03 4.08 5.81
2028/2029 4.25 4.16 5.80 5.15 4.16 6.07 5.21 4.16 6.12
2029/2030 4.34 4.03 5.87 5.30 4.03 6.39 5.37 4.03 6.50
2030/2031 4.37 4.00 5.86 5.65 4.00 6.66 5.66 4.00 7.02
2031/2032 4.60 4.15 6.09 6.33 4.15 7.01 6.35 4.15 7.37
2032/2033 4.92 4.45 6.51 6.32 4.45 7.91 6.44 4.45 8.05
2033/2034 5.15 4.64 6.71 6.79 4.64 8.49 6.91 4.64 8.47
2034/2035 5.34 4.80 6.85 6.82 4.79 8.93 7.03 4.79 9.04
2035/2036 5.43 4.89 6.96 7.11 4.89 9.20 7.41 4.89 9.28
2036/2037 5.66 5.08 7.13 7.23 5.08 9.53 7.58 5.08 9.59
2037/2038 5.79 5.24 7.26 7.34 5.23 9.74 7.52 5.23 9.87
2038/2039 5.93 5.43 7.46 7.55 5.43 10.24 7.81 5.43 10.28
2039/2040 6.08 5.64 7.66 7.78 5.64 9.89 8.05 5.65 10.55
2040/2041 6.40 5.91 7.91 8.09 5.91 10.49 8.22 5.91 10.85
2041/2042 6.55 6.09 8.10 8.24 6.10 10.68 8.55 6.10 11.13
2042/2043 6.73 6.24 8.22 8.86 6.24 10.90 8.85 6.24 11.33
2043/2044 6.89 6.44 8.39 8.81 6.44 11.28 9.15 6.44 11.55
2044/2045 7.12 6.67 8.59 9.14 6.67 11.25 9.42 6.68 12.03
Avista Corp 2025 Gas IRP DRAFT 3
2025 Natural Gas IRP Appendix 49

2045/2046 7.20 6.83 1 8.39 9.65 1 6.83 10.10 10.35 1 6.84 1 12.31
�A WA 1�= WA I D Winter RCP.UjjbMML JJW.5 Weather Resiliency
WA I Qq,AINJ
-
2025/2026 4.32 3.38 4.63 4.31 3.38 4.63 5.26 4.24 4.63
2026/2027 4.64 3.94 5.66 4.65 3.94 5.66 5.53 4.73 5.66
2027/2028 5.02 4.08 5.81 5.02 4.08 5.81 5.90 4.87 5.81
2028/2029 5.21 4.16 6.11 5.21 4.16 6.10 6.09 4.96 6.12
2029/2030 5.37 4.03 6.39 5.37 4.03 6.36 6.26 4.88 6.51
2030/2031 5.66 4.00 7.09 5.66 4.00 6.94 6.57 4.86 6.95
2031/2032 6.35 4.15 7.39 6.34 4.15 7.31 7.24 5.03 7.32
2032/2033 6.45 4.45 8.02 6.43 4.45 8.07 7.48 5.34 8.24
2033/2034 6.91 4.64 8.45 6.91 4.64 8.54 7.82 5.54 8.50
2034/2035 7.03 4.80 9.02 7.02 4.79 8.97 7.98 5.70 9.02
2035/2036 7.42 4.89 9.33 7.36 4.89 9.27 8.29 5.82 9.29
2036/2037 7.56 5.08 9.56 7.63 5.08 9.61 8.56 6.00 9.72
2037/2038 7.52 5.23 9.91 7.51 5.23 9.96 8.49 6.16 9.95
2038/2039 7.79 5.43 10.26 7.84 5.43 10.36 8.81 6.38 10.38
2039/2040 7.90 5.65 10.49 7.93 5.65 10.43 9.04 6.60 10.45
2040/2041 8.23 5.91 10.72 8.18 5.91 10.79 9.17 6.87 10.87
2041/2042 8.45 6.10 11 .07 8.48 6.10 11.22 9.59 7.07 11.24
2042/2043 8.87 6.24 11.17 8.79 6.24 11.13 9.83 7.22 11.34
2043/2044 9.15 6.44 11 .70 9.15 6.44 11.60 10.17 7.43 11.85
2044/2045 9.42 6.67 11.89 9.48 6.68 12.00 10.43 7.66 12.22
2045/2046 10.35 6.84 12.02 10.34 6.83 11.67 9.45 7.78 12.27
Wintero
Pit W- M 7 m
2025/2026 4.32 3.38 4.62
2026/2027 4.64 3.94 5.65
2027/2028 5.03 4.08 5.83
2028/2029 5.22 4.17 6.05
2029/2030 5.36 4.04 7.37
2030/2031 7.23 4.01 7.34
2031/2032 9.16 4.16 7.73
2032/2033 9.44 4.45 10.13
2033/2034 9.94 4.65 11.73
2034/2035 10.53 4.80 13.11
2035/2036 12.56 4.91 11.31
2036/2037 12.62 5.10 12.23
2037/2038 12.19 5.25 14.13
2038/2039 12.54 5.45 14.64
Avista Corp 2025 Gas IRP DRAFT 4
2025 Natural Gas IRP Appendix 50

2039/2040 13.06 5.67 13.66
2040/2041 13.04 5.93 15.03
2041/2042 14.03 6.12 13.82
2042/2043 13.24 6.27 15.12
2043/2044 14.13 6.47 15.32
2044/2045 13.70 6.69 16.13
2045/2046 10.99 6.76 15.00
Commercial Customers
Winter AverageDiversified Case Portfolio High Alternative Fu
Ill 4iwWA ID • Costs
- , OR
WA , • -
2025/2026 4.34 3.33 4.42 4.39 3.37 3.98 4.38 3.37 3.98
2026/2027 4.63 3.70 5.49 4.72 3.91 4.99 4.72 3.91 5.00
2027/2028 5.03 3.81 5.86 5.08 4.03 5.15 5.09 4.03 5.16
2028/2029 5.23 3.89 6.28 5.26 4.11 5.31 5.27 4.11 5.44
2029/2030 5.41 3.98 6.38 5.41 3.99 8.50 5.43 3.99 5.83
2030/2031 5.75 3.95 7.05 9.48 3.95 6.64 5.71 3.95 6.34
2031/2032 6.37 4.09 7.40 10.53 4.09 8.20 6.38 4.09 6.74
2032/2033 6.58 4.39 8.17 10.09 4.39 9.68 6.47 4.39 7.39
2033/2034 6.97 4.57 8.60 10.25 4.58 11.23 6.93 4.57 8.07
2034/2035 7.25 4.73 9.06 10.81 4.73 11.45 7.09 4.73 8.67
2035/2036 7.57 4.83 9.36 10.21 4.84 13.11 7.54 4.84 9.03
2036/2037 7.81 5.02 9.77 11.14 5.04 13.01 7.68 5.04 9.19
2037/2038 7.84 5.19 10.03 11.85 5.20 13.57 7.67 5.20 9.54
2038/2039 8.17 5.38 10.32 10.74 5.40 15.52 8.04 5.40 10.02
2039/2040 8.45 5.60 10.71 11.22 5.62 14.30 8.10 5.62 10.28
2040/2041 8.74 5.85 11.21 11.31 5.88 15.31 8.28 5.88 10.75
2041/2042 9.03 6.04 11.52 11.27 6.06 15.06 8.72 6.06 11.06
2042/2043 9.35 6.19 11.93 10.99 6.21 15.89 9.04 6.20 11.47
2043/2044 9.71 6.40 12.32 10.80 6.41 15.99 9.34 6.41 11.78
2044/2045 10.23 6.63 12.40 11.70 6.63 15.75 9.62 6.63 11.33
2045/2046 11.31 7.01 12.56 12.68 6.79 15.42 10.49 6.79 11.21
Ic - L7 nr;��
AM
2025/2026 4.58 3.37 3.99 14.43 174 3.98 4.38 3.35 3.84
2026/2027 4.93 3.91 5.00 4.79 4.00 5.00 4.74 3.89 4.95
2027/2028 5.37 4.03 5.16 7.41 5.54 5.18 5.13 4.01 5.28
2028/2029 5.58 4.11 5.44 9.78 6.96 5.35 5.32 4.09 5.70
2029/2030 5.76 3.99 5.78 10.81 8.45 5.63 5.49 3.98 5.84
2030/2031 6.12 3.95 6.23 12.85 9.53 5.38 5.78 3.95 6.41
Avista Corp 2025 Gas IRP DRAFT 5
2025 Natural Gas IRP Appendix 51

2031/2032 6.92 4.09 6.61 16.15 11.16 5.62 6.36 4.09 6.91
2032/2033 7.05 4.39 7.37 18.72 13.16 6.44 6.58 4.38 7.75
2033/2034 7.46 4.57 7.83 22.26 15.05 6.51 6.95 4.57 8.33
2034/2035 7.64 4.73 8.32 24.94 17.15 7.41 7.23 4.73 8.88
2035/2036 8.21 4.84 8.80 31.16 23.68 7.52 7.55 4.83 9.26
2036/2037 8.47 5.04 9.00 37.73 29.42 7.70 7.79 5.02 9.66
2037/2038 8.28 5.20 9.44 45.43 33.56 7.90 7.74 5.19 9.90
2038/2039 8.60 5.40 9.81 55.84 41.97 8.09 8.06 5.38 10.31
2039/2040 9.29 5.62 9.82 70.04 53.71 7.67 8.39 5.60 10.72
2040/2041 9.64 5.88 10.35 87.29 73.65 7.62 8.51 5.86 11.28
2041/2042 9.45 6.06 10.59 150.20 99.93 7.93 8.86 6.04 11.73
2042/2043 9.82 6.20 10.61 227.92 133.60 7.29 9.14 6.18 11.85
2043/2044 10.29 6.41 10.97 292.15 175.00 7.44 9.51 6.39 12.34
2044/2045 10.59 6.63 10.82 390.28 221.18 4.15 9.82 6.62 12.60
2045/2046 12.06 6.79 10.40 445.83 242.65 2.02 11.01 6.79 12.71
• - w mim 7 • -
2025/2026 4.68 3.56 4.18 4.38 3.37 3.98 4.38 3.37 3.98
2026/2027 5.70 4.73 5.98 4.72 3.91 5.00 4.75 3.91 5.00
2027/2028 6.67 5.30 6.60 5.76 6.85 5.17 5.13 4.03 5.16
2028/2029 7.26 5.80 7.32 7.48 7.47 5.40 5.31 4.11 5.44
2029/2030 7.73 6.11 7.73 8.65 6.83 5.67 5.49 3.99 5.77
2030/2031 8.22 6.13 8.25 9.37 7.49 6.01 5.79 3.95 6.26
2031/2032 9.65 6.54 8.28 10.33 8.60 6.69 6.35 4.09 6.46
2032/2033 9.84 7.50 10.17 10.96 9.58 6.79 6.56 4.39 7.20
2033/2034 10.78 7.78 10.60 12.09 10.39 7.30 6.94 4.58 7.57
2034/2035 11.23 8.55 11.09 12.72 11.43 7.83 7.25 4.73 8.13
2035/2036 11.72 8.74 11.63 15.05 13.14 8.15 7.54 4.84 8.46
2036/2037 12.11 9.17 11.63 16.70 15.08 8.37 7.79 5.04 8.79
2037/2038 12.51 9.62 12.49 16.90 18.24 8.73 7.75 5.20 9.10
2038/2039 14.03 10.06 12.58 18.92 20.06 9.16 8.10 5.40 9.53
2039/2040 13.89 11.12 13.18 22.32 18.84 9.28 8.39 5.62 9.67
2040/2041 14.54 11.60 13.76 24.82 19.30 9.57 8.74 5.88 10.11
2041/2042 14.36 11.47 13.58 27.95 20.77 9.90 8.90 6.06 10.35
2042/2043 15.28 11.67 13.79 31.28 22.27 9.85 9.20 6.20 10.46
2043/2044 16.44 12.60 14.50 33.05 26.02 10.22 9.57 6.41 10.76
2044/2045 15.86 13.40 13.71 39.43 26.33 10.43 9.87 6.63 10.95
2045/2046 17.15 13.41 13.79 43.79 25.48 10.16 11 .09 6.79 10.78
Avista Corp 2025 Gas IRP DRAFT 6
2025 Natural Gas IRP Appendix 52

. ' .
Costs
1 1
• • ' • •
2025/2026 4.39 3.37 3.98 4.88 3.59 4.20 4.39 3.37 3.98
2026/2027 4.72 3.91 5.00 5.92 4.73 6.01 4.72 3.91 5.00
2027/2028 5.09 4.03 5.16 6.97 5.32 6.63 5.10 4.03 5.16
2028/2029 5.27 4.11 5.44 7.60 5.81 7.28 5.27 4.11 5.44
2029/2030 5.43 3.99 5.72 8.07 6.14 7.88 5.45 3.99 6.93
2030/2031 5.71 3.95 6.09 9.02 6.15 8.39 8.14 3.95 7.44
2031/2032 6.38 4.09 6.21 10.43 6.57 8.70 11 .92 4.09 6.24
2032/2033 6.48 4.39 6.92 10.64 7.53 10.26 13.98 4.39 7.50
2033/2034 6.94 4.58 7.32 11.49 7.82 10.39 13.12 4.58 8.20
2034/2035 7.09 4.73 7.80 11.88 8.61 11.64 14.61 4.73 9.59
2035/2036 7.54 4.84 8.12 12.47 8.80 12.25 13.65 4.84 11.70
2036/2037 7.71 5.04 8.42 13.30 9.25 12.31 14.29 5.04 11.98
2037/2038 7.66 5.20 8.76 13.30 9.67 12.96 14.21 5.20 12.73
2038/2039 7.95 5.40 9.18 14.92 10.15 13.22 14.79 5.40 12.51
2039/2040 8.22 5.62 9.43 14.90 11 .12 14.16 14.38 5.62 14.19
2040/2041 8.47 5.88 9.60 15.63 11 .69 14.50 14.22 5.88 15.08
2041/2042 8.73 6.06 10.04 15.31 11.55 14.40 14.81 6.06 14.78
2042/2043 9.04 6.20 9.95 16.52 11 .72 14.82 15.43 6.20 15.29
2043/2044 9.34 6.41 10.44 17.60 12.59 15.76 16.48 6.41 14.97
2044/2045 9.62 6.63 10.50 16.73 13.04 14.62 15.38 6.63 15.58
2045/2046 10.49 6.79 10.54 18.58 13.33 14.60 14.14 6.79 12.83
Winter No Climate Programs
As Strategy
a WA ID ML • -
2025/2026 3.74 3.37 3.98 4.38 3.37 3.98 4.39 3.37 3.98
2026/2027 4.00 3.91 4.88 4.70 3.91 5.01 4.72 3.91 5.00
2027/2028 4.20 4.03 5.02 5.06 4.03 5.19 5.09 4.03 5.16
2028/2029 4.29 4.11 5.13 5.23 4.11 5.40 5.27 4.11 5.44
2029/2030 4.38 3.99 5.15 5.38 3.99 5.64 5.43 3.99 5.75
2030/2031 4.38 3.95 5.08 5.74 3.95 5.87 5.71 3.95 6.19
2031/2032 4.60 4.09 5.24 6.41 4.09 6.15 6.38 4.09 6.47
2032/2033 4.92 4.39 5.58 6.42 4.39 7.03 6.47 4.39 7.06
2033/2034 5.15 4.57 5.76 6.90 4.58 7.54 6.94 4.58 7.52
2034/2035 5.36 4.73 5.96 6.98 4.73 8.03 7.09 4.73 8.21
2035/2036 5.48 4.84 6.10 7.31 4.84 8.38 7.49 4.84 8.41
2036/2037 5.73 5.04 6.27 7.48 5.04 8.72 7.69 5.04 8.73
2037/2038 5.89 5.20 6.41 7.62 5.20 8.94 7.66 5.20 9.02
Avista Corp 2025 Gas IRP DRAFT 7
2025 Natural Gas IRP Appendix 53

2038/2039 6.05 5.40 6.63 7.88 5.40 9.50 7.98 5.40 9.45
2039/2040 6.23 5.62 6.86 8.14 5.62 9.15 8.25 5.62 9.77
2040/2041 6.53 5.88 7.11 8.45 5.88 9.74 8.42 5.88 10.10
2041/2042 6.68 6.06 7.31 8.59 6.06 9.97 8.73 6.06 10.37
2042/2043 6.84 6.20 7.37 9.18 6.20 10.18 9.03 6.20 10.50
2043/2044 7.01 6.41 7.51 9.15 6.41 10.52 9.34 6.41 10.73
2044/2045 7.25 6.63 7.42 9.49 6.63 10.10 9.62 6.63 10.88
2045/2046 7.32 6.79 7.01 9.92 6.79 8.56 10.49 6.79 10.85
2025/2026 4.39 3.37 3.98 4.39 3.37 3.98 5.34 4.23 3.98
2026/2027 4.72 3.91 5.01 4.72 3.91 5.00 5.61 4.70 5.01
2027/2028 5.09 4.03 5.16 5.09 4.03 5.17 5.97 4.82 5.16
2028/2029 5.27 4.11 5.43 5.27 4.11 5.42 6.15 4.91 5.44
2029/2030 5.43 3.99 5.63 5.43 3.99 5.64 6.31 4.84 5.77
2030/2031 5.71 3.95 6.27 5.71 3.95 6.18 6.62 4.81 6.13
2031/2032 6.38 4.09 6.51 6.37 4.09 6.45 7.27 4.97 6.43
2032/2033 6.48 4.39 7.17 6.47 4.39 7.17 7.51 5.28 7.31
2033/2034 6.94 4.58 7.55 6.94 4.58 7.63 7.85 5.48 7.53
2034/2035 7.09 4.73 8.10 7.08 4.73 8.12 8.04 5.64 8.12
2035/2036 7.50 4.84 8.40 7.45 4.84 8.39 8.38 5.76 8.41
2036/2037 7.67 5.04 8.68 7.73 5.04 8.69 8.67 5.96 8.83
2037/2038 7.66 5.20 9.07 7.66 5.20 9.12 8.63 6.13 9.08
2038/2039 7.96 5.40 9.38 8.02 5.40 9.50 8.99 6.35 9.55
2039/2040 8.10 5.62 9.64 8.13 5.62 9.64 9.24 6.58 9.64
2040/2041 8.43 5.88 9.94 8.37 5.88 9.95 9.37 6.84 10.09
2041/2042 8.64 6.06 10.25 8.67 6.07 10.41 9.77 7.03 10.47
2042/2043 9.05 6.20 10.34 8.97 6.21 10.31 10.00 7.18 10.49
2043/2044 9.34 6.41 10.80 9.33 6.41 10.70 10.36 7.39 10.97
2044/2045 9.62 6.63 10.71 9.67 6.63 10.82 10.63 7.62 11.04
2045/2046 10.48 6.79 10.64 10.48 6.79 10.31 9.59 7.73 10.90
2025/2026 4.40 3.37 3.97
2026/2027 4.72 3.91 5.00
2027/2028 5.10 4.03 5.18
2028/2029 5.28 4.12 5.37
2029/2030 5.41 4.00 6.60
2030/2031 7.28 3.96 6.45
2031/2032 9.15 4.10 6.87
Avista Corp 2025 Gas IRP DRAFT 8
2025 Natural Gas IRP Appendix 54

2032/2033 9.42 4.39 9.16
2033/2034 9.87 4.59 10.71
2034/2035 10.49 4.74 12.18
2035/2036 12.54 4.86 10.35
2036/2037 12.64 5.06 11.28
2037/2038 12.18 5.22 13.18
2038/2039 12.56 5.42 13.68
2039/2040 13.10 5.64 12.76
2040/2041 13.07 5.90 14.08
2041/2042 14.05 6.09 12.89
2042/2043 13.28 6.23 14.22
2043/2044 14.15 6.44 14.34
2044/2045 13.77 6.65 14.89
2045/2046 11.11 6.71 13.61
Industrial Customers
- • • MOW-
1
2025/2026 4.42 3.31 5.48 4.45 3.35 6.20 4.45 3.35 6.23
2026/2027 4.72 3.66 6.66 4.80 3.88 7.33 4.80 3.88 7.34
2027/2028 5.10 3.77 7.05 5.15 4.00 7.57 5.16 4.00 7.58
2028/2029 5.30 3.85 7.52 5.32 4.08 7.80 5.33 4.08 7.92
2029/2030 5.49 3.99 7.85 5.46 4.01 11.72 5.48 4.01 8.69
2030/2031 5.84 3.97 8.37 9.44 4.00 9.61 5.77 4.00 9.35
2031/2032 6.42 4.10 8.94 10.31 4.13 10.93 6.39 4.13 9.20
2032/2033 6.64 4.39 9.35 9.84 4.42 13.15 6.50 4.42 9.67
2033/2034 7.02 4.57 9.70 10.05 4.60 14.62 6.93 4.60 10.12
2034/2035 7.30 4.72 9.86 10.44 4.75 14.28 7.08 4.75 10.63
2035/2036 7.61 4.82 10.39 9.89 4.86 14.58 7.51 4.86 10.85
2036/2037 7.85 5.01 10.64 10.82 5.05 15.15 7.64 5.05 10.85
2037/2038 7.88 5.18 10.74 11.54 5.21 14.78 7.63 5.21 10.77
2038/2039 8.24 5.37 10.72 10.47 5.42 15.73 8.00 5.42 10.73
2039/2040 8.54 5.60 10.55 10.98 5.64 14.77 8.11 5.64 10.17
2040/2041 8.83 5.84 11.24 11.00 5.89 15.00 8.31 5.89 10.54
2041/2042 9.16 6.03 11 .62 10.99 6.08 14.81 8.77 6.08 11.02
2042/2043 9.51 6.18 12.13 10.84 6.23 16.07 9.14 6.22 11.05
2043/2044 9.90 6.39 12.22 10.78 6.43 15.54 9.47 6.43 11.86
2044/2045 10.41 6.62 12.99 11.71 6.65 14.63 9.77 6.65 11.51
2045/2046 11.46 7.00 13.70 12.56 6.81 16.60 10.60 6.81 11.86
igh CCA Allowance High Electrification High Growth on t
Pricing Gas System
Avista Corp 2025 Gas IRP DRAFT 9
2025 Natural Gas IRP Appendix 55

2025/2026 4.65 3.35 6.20 4.49 3.40 6.23 4.45 3.33 5.89
2026/2027 5.03 3.88 7.33 4.87 3.97 7.33 4.83 3.86 7.15
2027/2028 5.45 4.00 7.57 7.48 5.51 7.61 5.21 3.98 7.52
2028/2029 5.65 4.08 7.91 9.54 6.83 7.82 5.39 4.06 8.01
2029/2030 5.83 4.01 8.48 10.24 8.12 8.21 5.55 3.99 8.69
2030/2031 6.20 4.00 8.95 11.79 8.91 8.06 5.85 3.97 9.01
2031/2032 6.95 4.13 9.11 14.22 10.08 7.99 6.39 4.10 9.31
2032/2033 7.10 4.42 9.98 15.71 11 .45 8.67 6.61 4.40 10.17
2033/2034 7.49 4.60 10.24 17.83 12.55 8.56 6.95 4.57 10.36
2034/2035 7.65 4.75 10.38 18.89 13.66 8.89 7.23 4.72 10.70
2035/2036 8.21 4.86 10.07 22.25 17.68 8.69 7.53 4.83 10.86
2036/2037 8.47 5.05 10.06 25.08 20.66 8.76 7.76 5.01 11.02
2037/2038 8.28 5.21 10.35 27.87 22.02 8.66 7.71 5.18 11.01
2038/2039 8.62 5.42 10.66 31.49 25.33 8.50 8.04 5.38 10.94
2039/2040 9.32 5.64 10.17 35.65 29.45 7.26 8.39 5.60 11.07
2040/2041 9.67 5.90 9.96 39.86 36.01 6.57 8.53 5.85 11.38
2041/2042 9.56 6.08 10.38 58.81 42.87 6.71 8.90 6.04 11.79
2042/2043 9.98 6.22 10.50 75.44 49.33 5.59 9.22 6.18 11.81
2043/2044 10.48 6.43 11.17 80.65 54.56 5.53 9.62 6.39 12.55
2044/2045 10.81 6.65 10.74 87.97 55.65 2.55 9.95 6.61 12.79
2045/2046 12.20 6.81 11.30 90.61 55.14 1.03 11.09 6.79 13.43
P
2025/2026 4.75 ;3. 6.43 4.45 3.34 6.28 4.45 3.35 6.28
2026/2027 5.81 4.72 8.30 4.80 3.88 7.35 4.84 3.88 7.33
2027/2028 6.75 5.27 9.01 5.85 6.82 7.59 5.21 4.00 7.60
2028/2029 7.34 5.77 9.78 7.55 7.40 7.88 5.40 4.08 7.93
2029/2030 7.79 6.14 10.47 8.67 6.79 8.43 5.57 4.01 8.89
2030/2031 8.27 6.17 10.89 9.35 7.44 8.98 5.88 3.99 9.11
2031/2032 9.63 6.59 10.85 10.25 8.46 8.99 6.41 4.13 8.91
2032/2033 9.89 7.54 12.72 10.85 9.37 8.80 6.63 4.42 9.63
2033/2034 10.75 7.81 12.89 11 .88 10.08 9.17 6.99 4.60 9.71
2034/2035 11.24 8.58 12.96 12.45 11.00 9.61 7.30 4.75 9.91
2035/2036 11.69 8.76 13.15 14.64 12.53 9.46 7.58 4.86 9.72
2036/2037 12.07 9.20 13.22 16.09 14.23 9.39 7.83 5.05 9.77
2037/2038 12.49 9.64 13.34 16.18 16.99 9.60 7.80 5.22 10.11
2038/2039 13.95 10.09 13.18 18.01 18.51 9.49 8.17 5.41 10.08
2039/2040 13.90 11.14 13.45 21.01 17.31 9.00 8.48 5.64 9.91
2040/2041 14.44 11.63 13.37 23.08 17.56 9.13 8.82 5.90 9.84
2041/2042 14.41 11.47 13.39 25.70 18.70 9.57 9.03 6.08 10.08
Avista Corp 2025 Gas IRP DRAFT 10
2025 Natural Gas IRP Appendix 56

2042/2043 15.35 11.70 13.31 28.38 19.81 9.53 9.37 6.22 9.58
2043/2044 16.57 12.63 14.16 29.59 22.77 9.85 9.76 6.43 10.66
2044/2045 15.97 13.42 13.52 34.69 22.88 10.18 10.09 6.65 10.64
2045/2046 17.24 13.38 13.65 38.08 22.09 9.87 11 .25 6.81 10.62
Alternative F=ue ' Low Natural Gas Use No - .
Costs Allowances After
r ;.
2025/2026 4.45 3.35 6.35 4.96 3.57 6.39 4.46 3.35 6.23
2026/2027 4.80 3.88 7.34 6.06 4.72 8.31 4.80 3.88 7.35
2027/2028 5.16 4.00 7.59 7.08 5.28 8.98 5.16 4.00 7.58
2028/2029 5.33 4.08 7.91 7.71 5.78 9.72 5.33 4.08 7.92
2029/2030 5.48 4.01 8.36 8.16 6.16 11.04 5.51 4.01 10.49
2030/2031 5.77 4.00 8.76 9.10 6.19 11.26 8.27 3.99 10.84
2031/2032 6.39 4.13 8.73 10.45 6.60 11.70 11 .82 4.13 8.58
2032/2033 6.50 4.42 9.33 10.73 7.57 13.22 13.91 4.42 9.84
2033/2034 6.93 4.60 9.26 11.49 7.83 13.28 13.08 4.60 10.16
2034/2035 7.08 4.75 9.44 11.94 8.62 13.56 14.51 4.75 10.90
2035/2036 7.51 4.86 9.49 12.50 8.80 13.95 13.34 4.86 13.61
2036/2037 7.68 5.05 9.55 13.29 9.24 14.01 13.90 5.05 12.83
2037/2038 7.63 5.21 9.27 13.32 9.67 14.42 13.90 5.21 13.45
2038/2039 7.93 5.42 9.54 14.89 10.16 14.41 14.43 5.42 12.71
2039/2040 8.23 5.64 9.42 14.96 11 .13 14.65 14.11 5.64 14.88
2040/2041 8.48 5.89 9.39 15.64 11 .69 14.58 13.92 5.89 14.24
2041/2042 8.78 6.08 9.95 15.42 11 .52 14.41 14.55 6.08 14.07
2042/2043 9.14 6.22 9.70 16.63 11 .72 14.49 15.42 6.22 13.98
2043/2044 9.47 6.43 10.12 17.81 12.60 15.55 16.50 6.43 13.36
2044/2045 9.78 6.65 10.18 16.93 13.03 14.44 15.16 6.65 15.13
2045/2046 10.61 6.81 10.47 18.72 13.27 14.66 14.14 6.81 12.36
ProgramsWinter No Climate
Stratei.
WA ID OR
2025/2026 3.78 3.34 6.28 4.45 3.35 6.35 4.46 3.3540'
2026/2027 4.04 3.88 7.23 4.77 3.88 7.35 4.80 3.88 7.34
2027/2028 4.21 3.99 7.41 5.11 4.00 7.61 5.16 4.00 7.58
2028/2029 4.30 4.08 7.61 5.27 4.08 7.89 5.33 4.08 7.92
2029/2030 4.37 4.01 7.68 5.41 4.01 8.32 5.48 4.01 8.67
2030/2031 4.35 3.99 7.56 5.74 4.00 8.58 5.77 3.99 8.78
2031/2032 4.53 4.13 7.55 6.36 4.13 8.62 6.39 4.13 9.03
2032/2033 4.85 4.42 7.76 6.37 4.42 8.94 6.49 4.42 9.42
2033/2034 5.06 4.60 7.71 6.81 4.60 9.30 6.93 4.60 9.69
Avista Corp 2025 Gas IRP DRAFT 11
2025 Natural Gas IRP Appendix 57

2034/2035 5.24 4.75 7.60 6.88 4.75 9.49 7.08 4.75 9.50
2035/2036 5.35 4.86 7.41 7.17 4.86 9.45 7.46 4.86 9.80
2036/2037 5.58 5.05 7.32 7.31 5.05 9.58 7.65 5.05 9.71
2037/2038 5.74 5.22 7.21 7.44 5.21 9.52 7.63 5.21 9.89
2038/2039 5.90 5.42 7.06 7.70 5.42 9.71 7.96 5.42 10.05
2039/2040 6.10 5.64 6.76 7.98 5.64 9.19 8.25 5.64 9.78
2040/2041 6.41 5.89 6.80 8.30 5.89 9.32 8.43 5.90 9.85
2041/2042 6.58 6.08 6.93 8.48 6.08 9.54 8.78 6.08 10.05
2042/2043 6.78 6.22 7.02 9.12 6.22 9.63 9.12 6.22 10.46
2043/2044 6.97 6.42 7.19 9.13 6.43 9.80 9.47 6.43 10.22
2044/2045 7.22 6.64 7.30 9.50 6.65 9.53 9.77 6.65 11.23
2045/2046 7.30 6.81 7.05 9.91 6.81 9.67 10.61 6.81 12.31
2025/2026 4.46 3.34 6.27 4.45 3.35 6.26 5.42 4.22 6.41
2026/2027 4.80 3.88 7.32 4.80 3.88 7.35 5.69 4.67 7.35
2027/2028 5.16 4.00 7.57 5.16 4.00 7.59 6.04 4.79 7.59
2028/2029 5.33 4.08 7.92 5.33 4.08 7.92 6.21 4.89 7.93
2029/2030 5.48 4.01 8.40 5.48 4.01 8.33 6.37 4.86 8.50
2030/2031 5.77 3.99 9.08 5.77 3.99 8.80 6.67 4.86 8.87
2031/2032 6.39 4.13 8.90 6.39 4.13 8.83 7.28 5.01 8.96
2032/2033 6.51 4.42 9.28 6.49 4.42 9.34 7.53 5.31 9.94
2033/2034 6.93 4.60 9.35 6.93 4.60 9.39 7.85 5.50 9.81
2034/2035 7.08 4.75 9.71 7.08 4.75 9.43 8.03 5.66 10.06
2035/2036 7.47 4.86 9.91 7.42 4.86 9.96 8.36 5.78 9.91
2036/2037 7.64 5.05 10.09 7.69 5.05 9.96 8.63 5.97 10.29
2037/2038 7.63 5.22 9.95 7.62 5.21 9.98 8.60 6.15 10.39
2038/2039 7.94 5.42 10.00 8.00 5.42 9.90 8.96 6.36 10.20
2039/2040 8.10 5.64 9.77 8.14 5.64 9.83 9.24 6.60 9.87
2040/2041 8.45 5.90 9.69 8.39 5.90 10.12 9.39 6.86 9.86
2041/2042 8.69 6.08 10.10 8.72 6.09 10.39 9.82 7.05 10.43
2042/2043 9.15 6.22 10.02 9.06 6.22 10.14 10.09 7.20 10.45
2043/2044 9.46 6.43 10.57 9.46 6.43 10.47 10.49 7.41 10.98
2044/2045 9.77 6.65 10.65 9.82 6.65 10.70 10.78 7.63 11.20
2045/2046 10.59 6.81 10.97 10.58 6.81 10.49 9.86 7.75 10.94
sm me]-
2025/2026 4.46 3.35 6.24
2026/2027 4.79 3.88 7.32
2027/2028 5.16 4.00 7.61
Avista Corp 2025 Gas IRP DRAFT 12
2025 Natural Gas IRP Appendix 58

2028/2029 5.34 4.09 7.87
2029/2030 5.46 4.02 9.87
2030/2031 7.34 4.00 9.78
2031/2032 8.97 4.13 9.68
2032/2033 9.20 4.42 11 .65
2033/2034 9.60 4.61 12.84
2034/2035 10.13 4.76 13.90
2035/2036 12.20 4.88 11.86
2036/2037 12.35 5.07 12.25
2037/2038 11.79 5.23 14.30
2038/2039 12.15 5.43 14.81
2039/2040 12.76 5.66 12.50
2040/2041 12.70 5.92 14.02
2041/2042 13.67 6.11 12.81
2042/2043 12.95 6.25 13.84
2043/2044 13.92 6.46 14.28
2044/2045 13.54 6.66 14.52
2045/2046 11.09 6.73 12.38
Transport Customers
DiversifiedWinter Average Case Portfolio High Alternative Fuel
EWA ID qLO M A Costs
2025/2026 3.87 N/A 3.55 3.89 N/A 2.89 1 3.89 N/A 2.89
2026/2027 4.42 N/A 4.19 4.43 N/A 3.38 4.43 N/A 3.38
2027/2028 4.91 N/A 4.57 4.89 N/A 3.47 4.91 N/A 3.47
2028/2029 5.23 N/A 5.03 5.21 N/A 3.81 5.23 N/A 3.81
2029/2030 5.34 N/A 5.42 5.32 N/A 5.11 5.34 N/A 4.11
2030/2031 5.86 N/A 5.75 7.46 N/A 5.09 5.85 N/A 4.61
2031/2032 6.58 N/A 6.39 6.49 N/A 8.48 6.57 N/A 5.27
2032/2033 6.86 N/A 7.20 6.88 N/A 8.17 6.86 N/A 5.96
2033/2034 6.99 N/A 7.75 7.01 N/A 7.28 6.99 N/A 6.51
2034/2035 7.33 N/A 8.35 7.35 N/A 10.00 7.33 N/A 7.15
2035/2036 7.68 N/A 8.51 7.68 N/A 6.26 7.68 N/A 7.17
2036/2037 7.95 N/A 8.80 7.96 N/A 6.92 7.95 N/A 7.38
2037/2038 8.24 N/A 9.22 8.25 N/A 7.70 8.24 N/A 7.89
2038/2039 8.59 N/A 9.57 8.59 N/A 7.72 8.59 N/A 8.27
2039/2040 9.07 N/A 10.12 9.07 N/A 10.28 9.07 N/A 8.80
2040/2041 9.38 N/A 10.58 9.38 N/A 8.78 9.38 N/A 9.26
2041/2042 9.59 N/A 11.14 9.60 N/A 10.98 9.59 N/A 9.81
2042/2043 9.66 N/A 11.38 9.67 N/A 9.76 9.66 N/A 10.05
2043/2044 10.19 N/A 11.97 10.19 N/A 10.42 10.19 N/A 10.65
2044/2045 10.65 N/A 12.62 10.65 N/A 10.83 10.65 N/A 11.31
Avista Corp 2025 Gas IRP DRAFT 13
2025 Natural Gas IRP Appendix 59

2045/2046 11.06 N/A 1 13.07 11.11 N/A 9.54 11.06 1 N/A 1 11.80
L--Winter IHigh CCA Allowance High Electrification High Growth on the-I
Pricing & Gas System
OR Ak ID OR • -
2025/2026 4.15 N/A 2.89 3.89 N/A 2.89 3.87 N/A 2.68
2026/2027 4.76 N/A 3.38 4.43 N/A 3.38 4.42 N/A 3.35
2027/2028 5.37 N/A 3.47 4.90 N/A 3.37 4.90 N/A 3.76
2028/2029 5.74 N/A 3.81 5.22 N/A 3.54 5.22 N/A 4.26
2029/2030 5.91 N/A 4.13 5.34 N/A 3.66 5.34 N/A 4.67
2030/2031 6.56 N/A 4.48 5.85 N/A 3.75 5.85 N/A 5.02
2031/2032 7.45 N/A 5.43 6.56 N/A 4.21 6.57 N/A 5.71
2032/2033 7.74 N/A 5.75 6.85 N/A 4.71 6.86 N/A 6.59
2033/2034 7.89 N/A 6.31 6.98 N/A 4.86 6.99 N/A 7.20
2034/2035 8.34 N/A 7.00 7.32 N/A 5.29 7.33 N/A 7.87
2035/2036 8.85 N/A 6.99 7.67 N/A 5.48 7.68 N/A 8.01
2036/2037 9.15 N/A 7.13 7.94 N/A 5.75 7.95 N/A 8.31
2037/2038 9.46 N/A 7.75 8.23 N/A 5.97 8.24 N/A 8.80
2038/2039 9.92 N/A 8.19 8.58 N/A 6.12 8.59 N/A 9.19
2039/2040 10.57 N/A 8.73 9.05 N/A 6.70 9.07 N/A 9.83
2040/2041 10.91 N/A 9.20 9.38 N/A 6.63 9.38 N/A 10.36
2041/2042 11.16 N/A 9.63 9.46 N/A 7.76 9.59 N/A 10.97
2042/2043 11.38 N/A 9.79 10.02 N/A 8.01 9.66 N/A 11.25
2043/2044 12.14 N/A 10.26 11.37 N/A 4.48 10.19 N/A 11.95
2044/2045 12.65 N/A 10.84 11.96 N/A 3.74 10.65 N/A 12.67
2045/2046 13.09 N/A 11.33 12.90 N/A 4.98 11.06 N/A 13.14
HybridWinte High Natural Gas i6.
L:j A
- - • -
2025/2026 4.12 N/A 3.13 3.89 N/A 2.89 3.89 N/A 2.89
2026/2027 5.44 N/A 4.43 4.43 N/A 3.38 4.43 N/A 3.38
2027/2028 6.28 N/A 4.90 4.91 N/A 3.46 4.91 N/A 3.47
2028/2029 7.00 N/A 5.71 5.23 N/A 3.75 5.23 N/A 3.81
2029/2030 7.38 N/A 6.13 5.34 N/A 4.04 5.34 N/A 4.08
2030/2031 7.92 N/A 6.48 5.85 N/A 4.43 5.86 N/A 4.44
2031/2032 8.85 N/A 7.69 6.57 N/A 4.83 6.57 N/A 5.33
2032/2033 9.91 N/A 8.07 6.85 N/A 5.76 6.86 N/A 5.48
2033/2034 10.08 N/A 8.53 6.99 N/A 6.25 6.99 N/A 6.28
2034/2035 11.11 N/A 9.68 7.33 N/A 6.85 7.33 N/A 7.01
2035/2036 11.43 N/A 10.12 7.68 N/A 6.80 7.68 N/A 6.97
2036/2037 11.96 N/A 11.08 7.95 N/A 6.94 7.95 N/A 7.12
2037/2038 12.47 N/A 11.96 8.24 N/A 7.47 8.24 N/A 7.69
Avista Corp 2025 Gas IRP DRAFT 14
2025 Natural Gas IRP Appendix 60

2038/2039 13.09 N/A 12.57 8.59 N/A 7.86 8.59 N/A 8.10
2039/2040 14.24 N/A 14.02 9.06 N/A 8.33 9.07 N/A 8.60
2040/2041 14.92 N/A 14.42 9.38 N/A 8.74 9.38 N/A 9.03
2041/2042 14.72 N/A 14.54 9.59 N/A 9.15 9.59 N/A 9.65
2042/2043 14.93 N/A 14.76 9.66 N/A 9.30 9.66 N/A 9.93
2043/2044 16.38 N/A 16.23 10.19 N/A 9.62 10.19 N/A 10.42
2044/2045 17.38 N/A 17.53 10.65 N/A 10.09 10.65 N/A 11.00
2045/2046 17.46 N/A 17.97 11.06 N/A 10.58 11.06 N/A 11.49
2025/2026 3.89 N/A 2.89 4.39 N/A 3.13 3.89 N/A 2.89
2026/2027 4.43 N/A 3.38 5.77 N/A 4.43 4.43 N/A 3.38
2027/2028 4.91 N/A 3.47 6.73 N/A 4.89 4.91 N/A 3.47
2028/2029 5.23 N/A 3.81 7.51 N/A 5.53 5.23 N/A 3.81
2029/2030 5.34 N/A 4.10 7.95 N/A 5.96 5.35 N/A 3.73
2030/2031 5.85 N/A 4.37 8.63 N/A 6.68 9.14 N/A 3.80
2031/2032 6.57 N/A 5.30 9.73 N/A 7.33 15.24 N/A 4.91
2032/2033 6.86 N/A 5.45 10.81 N/A 7.83 15.65 N/A 6.06
2033/2034 6.99 N/A 6.36 10.98 N/A 8.63 15.90 N/A 6.76
2034/2035 7.33 N/A 6.98 12.12 N/A 9.89 14.11 N/A 7.51
2035/2036 7.68 N/A 6.96 12.61 N/A 10.34 10.94 N/A 8.17
2036/2037 7.95 N/A 7.12 13.16 N/A 11 .05 11 .27 N/A 8.72
2037/2038 8.24 N/A 7.67 13.68 N/A 11 .93 12.17 N/A 9.51
2038/2039 8.59 N/A 8.09 14.42 N/A 12.54 12.02 N/A 10.07
2039/2040 9.07 N/A 8.58 15.75 N/A 14.00 11.67 N/A 10.84
2040/2041 9.38 N/A 9.01 16.46 N/A 14.43 12.05 N/A 11.51
2041/2042 9.59 N/A 9.52 16.28 N/A 14.56 12.26 N/A 12.34
2042/2043 9.66 N/A 9.74 16.65 N/A 14.79 11 .76 N/A 12.82
2043/2044 10.19 N/A 10.37 18.32 N/A 16.26 12.71 N/A 13.69
2044/2045 10.65 N/A 11.05 19.38 N/A 17.53 13.13 N/A 14.59
2045/2046 11.06 N/A 11.52 19.51 N/A 17.99 13.01 N/A 15.18
ProgramsNo Climate
StrategyWh am IK WA ID
• - • �
2025/2026 2.98 1 N/A 2.89 3.89 N/A 2.89 3.89 N/A 2.89
2026/2027 3.34 N/A 3.38 4.43 N/A 3.38 4.43 N/A 3.38
2027/2028 3.44 N/A 3.46 4.91 N/A 3.46 4.91 N/A 3.47
2028/2029 3.57 N/A 3.55 5.23 N/A 3.61 5.23 N/A 3.81
2029/2030 3.50 N/A 3.57 5.34 N/A 3.86 5.34 N/A 4.12
Avista Corp 2025 Gas IRP DRAFT 15
2025 Natural Gas IRP Appendix 61

2030/2031 3.53 N/A 3.48 5.85 N/A 4.20 5.85 N/A 4.61
2031/2032 3.64 N/A 3.56 6.57 N/A 4.99 6.57 N/A 5.24
2032/2033 3.89 N/A 3.85 6.85 N/A 5.42 6.86 N/A 5.52
2033/2034 3.98 N/A 3.93 6.99 N/A 5.90 6.99 N/A 6.29
2034/2035 4.13 N/A 4.06 7.33 N/A 6.53 7.33 N/A 7.01
2035/2036 4.20 N/A 4.10 7.68 N/A 6.50 7.68 N/A 6.97
2036/2037 4.42 N/A 4.31 7.95 N/A 6.65 7.95 N/A 7.12
2037/2038 4.64 N/A 4.58 8.24 N/A 7.17 8.24 N/A 7.69
2038/2039 4.79 N/A 4.73 8.59 N/A 7.58 8.59 N/A 8.10
2039/2040 4.96 N/A 4.98 9.07 N/A 8.05 9.07 N/A 8.60
2040/2041 5.20 N/A 5.16 9.38 N/A 8.47 9.38 N/A 9.03
2041/2042 5.34 N/A 5.34 9.59 N/A 8.89 9.59 N/A 9.65
2042/2043 5.16 N/A 5.24 9.66 N/A 9.04 9.66 N/A 9.93
2043/2044 5.33 N/A 5.42 10.19 N/A 9.36 10.19 N/A 10.42
2044/2045 5.65 N/A 5.71 10.65 N/A 9.82 10.65 N/A 11.00
2045/2046 5.98 N/A 6.07 11.06 N/A 10.32 11 .06 N/A 11.49
sm D • - • - • -
2025/2026 3.89 N/A 2.89 3.89 N/A 2.89 3.89 N/A 2.89
2026/2027 4.43 N/A 3.38 4.43 N/A 3.38 4.43 N/A 3.38
2027/2028 4.91 N/A 3.47 4.91 N/A 3.46 4.91 N/A 3.47
2028/2029 5.23 N/A 3.80 5.23 N/A 3.78 5.23 N/A 3.81
2029/2030 5.34 N/A 4.08 5.34 N/A 4.10 5.34 N/A 3.96
2030/2031 5.85 N/A 4.26 5.85 N/A 4.43 5.85 N/A 4.47
2031/2032 6.57 N/A 5.32 6.57 N/A 5.35 6.57 N/A 5.41
2032/2033 6.86 N/A 5.73 6.86 N/A 5.62 6.86 N/A 5.65
2033/2034 6.99 N/A 6.34 6.99 N/A 6.29 6.99 N/A 6.35
2034/2035 7.33 N/A 6.98 7.33 N/A 6.96 7.33 N/A 7.01
2035/2036 7.68 N/A 6.94 7.68 N/A 6.92 7.68 N/A 6.97
2036/2037 7.95 N/A 7.10 7.95 N/A 7.08 7.95 N/A 7.12
2037/2038 8.24 N/A 7.66 8.24 N/A 7.64 8.24 N/A 7.69
2038/2039 8.59 N/A 8.07 8.59 N/A 8.04 8.59 N/A 8.10
2039/2040 9.07 N/A 8.56 9.07 N/A 8.53 9.07 N/A 8.60
2040/2041 9.38 N/A 8.99 9.38 N/A 8.96 9.38 N/A 9.03
2041/2042 9.59 N/A 9.60 9.59 N/A 9.57 9.59 N/A 9.65
2042/2043 9.66 N/A 9.89 9.66 N/A 9.86 9.66 N/A 9.93
2043/2044 10.19 N/A 10.36 10.19 N/A 10.30 10.19 N/A 10.42
2044/2045 10.65 N/A 10.94 10.65 N/A 10.85 10.65 N/A 11.00
2045/2046 11.06 N/A 11.43 11.06 N/A 11.34 11.06 N/A 11.49
rinter Social Cost of A
Greenhouse GaM,
Avista Corp 2025 Gas IRP DRAFT 16
2025 Natural Gas IRP Appendix 62

2025/2026 3.89 N/A 2.89
2026/2027 4.43 N/A 3.38
2027/2028 4.90 N/A 3.47
2028/2029 5.21 N/A 3.81
2029/2030 5.33 N/A 3.87
2030/2031 5.84 N/A 4.63
2031/2032 6.56 N/A 7.99
2032/2033 6.84 N/A 6.92
2033/2034 6.97 N/A 7.18
2034/2035 7.33 N/A 7.93
2035/2036 7.69 N/A 6.38
2036/2037 7.97 N/A 6.92
2037/2038 8.26 N/A 7.52
2038/2039 8.60 N/A 7.69
2039/2040 9.07 N/A 9.47
2040/2041 9.38 N/A 9.04
2041/2042 9.60 N/A 11.36
2042/2043 9.67 N/A 10.19
2043/2044 10.20 N/A 10.28
2044/2045 10.65 N/A 12.29
2045/2046 11.09 N/A 13.98
Avista Corp 2025 Gas IRP DRAFT 17
2025 Natural Gas IRP Appendix 63

Appendix 3.1 : Economic Considerations
Population
Population growth is increasingly a result of net migration to Avista's service area as more
people move here. Net migration is strongly associated with both service area and
national employment growth through the business cycle. The regional business cycle
follows the U.S. business cycle, meaning regional economic expansions or contractions
follow national economic trends.' Econometric analysis shows when regional
employment growth is stronger than U.S. growth over the business cycle, it is associated
with increased in-migration and the reverse holds true. Figure 1.1 shows annual
population growth since 1971 and highlights the recessions in yellow. During all deep
economic downturns since the mid-1970s, reduced population growth rates in Avista's
service territory led to lower load growth.2 The Great Recession reduced population
growth from nearly 2% in 2007 to less than 1% from 2010 to 2013. Accelerating service
area employment growth in 2013 helped push population growth above 1% after 2014.
Figure 1.1: MSA Population Growth and U.S. Recessions, 1971-2023
3.5%
3.0%
2.5%
2.0%
r
p 1.5%
1.0%
c
c
a 0.5%
0.0%
-0.5%
-1.0%
co lA r-- m co N r— O CM N h m co In r O M Ln m 7 co r__ f` 00 00 00 00 00 m m m m m O O O O O N N
m m m m m m m m m m m m m m m O O O O O O O O O O O O
N N N N N N N N N N N N
U.S. Recessionary Periods —Avista WA-ID MSAs Population Growth
An Exploration of Similarities between National and Regional Economic Activity in the Inland Northwest,
Monograph No. 11, May 2006. http://www.ewu.edu/cbpa/centers-and-institutes/ippea/monograph-
series.xml.
2 Data Source: Bureau of Economic Development, U.S. Census, and National Bureau of Economic
Research.
2025 Natural Gas IRP Appendix 64

Figure 1.2 shows population growth since 2012.3 Service area population growth between
2010 and 2012 was lower than the U.S.; however, it was closely associated with the
strength of regional employment growth relative to the U.S. over the same period. The
same can be said for the increase in service area population growth in 2014 relative to
the U.S. population growth. The association of employment growth to population growth
has a one-year lag. The relative strength of service area employment growth in year "y"
is positively associated with service area population growth in year "y+1". Econometric
estimates using historical data show when holding the U.S. employment-growth constant,
every 1% increase in service area employment growth is associated with a 0.4% increase
in population growth in the next year.
Figure 1.2: Avista and U.S. MSA Population Growth, 2012-2023
2.5%
■Avista WA-ID MSAs
■U.S. 2.0%
2.0% 1.9
1.8% 1.7%
1.6%
t
0 1.5% 1.4%
0
1.2%
� 1.1
7
1.0% 0.9%
Q 0.9%
0.8% 0.8% 0.8% 0.8%
0.7
iiii
0.6%
0.5% 0.5%
0.5% 0.4% 0.a%
0.2%
0.0%
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Employment
Given the correlation between population and employment growth, it is useful to examine
the distribution of employment and employment performance since 2012. The Inland
Northwest is a services-based economy rather than its former natural resources-based
manufacturing economy. Figure 1.3 shows the breakdown of non-farm employment for
all three-service area MSAs from the Bureau of Labor and Statistics. Almost 70% of
employment in the three MSAs is in private services (69%), followed by government
(17%) and private goods-producing sectors (15%). Farming accounts for 1% of total
3 Data Source: Bureau of Economic Analysis, U.S. Census, and Washington State Office of Financial
Management.
2025 Natural Gas IRP Appendix 65

employment. Spokane and Coeur d'Alene MSAs are major providers of health and higher
education services to the Inland Northwest.
Figure A: Avista's MSA Non-Farm Employment Breakdown by Major Sector, 2023
Local Government,)
11%
Private Goods
State Government, _Producing, 15%
4%
Federal Government,
2%
L Private Service
Producing, .•.
Following the Great Recession, regional employment recovery did not materialize until
2013, when services employment started to grow.4 Service area employment growth
began to match or exceed U.S. growth rates by the fourth quarter 2014. Since the COVID-
19 induced recession in 2020, service area employment has more than recovered from
the losses resulting from the nationwide shutdowns. Figure 1.4 compares Avista's
Washington and Idaho MSAs and the U.S. non-farm employment growth for 2012 to
2023.
4 Data Source: Bureau of Labor and Statistics.
2025 Natural Gas IRP Appendix 66

Figure 1.4: Avista and U.S. Non-Farm Employment Growth, 2012-2023
5.5%
4.3% 4.2%
3.5% 3.a
3.0% 29%
2.3
2.0% 1.9% 1.9% 2.1% 2.2%2.0% 2.0% 1.9%
1.7% 1.6%
1.5% 1.3%
w�. 0.6
3
0
L
0 -0.5%
R
7
C
C
Q -2.5%
■Avista WA-ID MSAs 3.8'
-4.5% ■U.S.
-6.5% -6.0%
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Figure 1.5 shows the distribution of personal income, a broad measure of both earned
income and transfer payments, for Avista's Washington and Idaho MSAs.5 Regular
income includes net earnings from employment, and investment income in the form of
dividends, interest, and rent. Personal current transfer payments include money income
and in-kind transfers received through unemployment benefits, low-income food
assistance, Social Security, Medicare, and Medicaid.
Transfer payments in Avista's service area in 1970 accounted for 12% of the local
economy. The income share of transfer payments has nearly doubled over the last 40
years locally to 23%. Although 56% of personal income is from net earnings, transfer
payments still account for more than one in every five dollars of personal income. Recent
years have seen transfer payments become the fastest growing component of regional
personal income. This growth in regional transfer payments reflects an aging regional
population, a surge of military veterans, and the lingering impacts of the COVID-19
transfer payments to households, including enhanced unemployment benefits.
Figure 1.6 shows the real (inflation adjusted) average annual growth per capita income
by MSA for Avista's service area and the U.S. overall. Although between 1980 and 1990,
the service area experienced significantly lower income growth compared to the U.S.
because of the back-to-back recessions of the early 1980s according to the Bureau of
Economic Analysis. The impacts of these recessions were more negative in the service
area compared to the U.S., so the ratio of service area per capita income to U.S. per
5 Data Source: Bureau of Economic Analysis.
2025 Natural Gas IRP Appendix 67

capita income fell from 93% in the 197Os to around 85% by the mid-199Os. The income
ratio has not recovered.
Figure 1.5: MSA Personal Income Breakdown by Major Source, 2022
Transfer
Receipts,23Net Earnings,
:'
Dividends,
Interest,and
Rent, 19% Fr
Figure 1.6: Avista and U.S. MSA Real Personal Income Growth
3.0%
■Avista WA-ID MSAs
■U.S.
4; 2.5% 2.4 0°
2.3% ° 2.3% 2.3%2.4%
2.2/o
t
2.1
3 2.0%
O n
,L^
V
1.5% 1.3%
c
c
Q 1.0%
0.8% 0.8%
CO
cv
L
d 0.5%
Q 0.5%
m
0.0%
NEW-
-0.1%
-0.5%
1970 to 1980 1980 to 1990 1990 to 2000 2000 to 2010 2010 to 2021 2020 to 2022
2025 Natural Gas IRP Appendix 68

Overview of the Medium-Term Retail Load Forecast
As described above, the load forecast for the 2025 IRP was done in three phases. The
following section describes the first phase — the development of a medium-term forecast
for the period 2026-2029. The forecast serves as the basis for the second phase, an end-
use forecast for the remaining period 2029 to 2045.
The medium-term forecast is based on a monthly use per customer (UPC) forecast and
a monthly customer forecast for each customer class in most rate schedules.6 The load
forecast multiplies the customer and UPC forecasts. The UPC and customer forecasts
are generated using time-series econometrics, as shown in Equation 1.1.
Equation 1.1: Generating Schedule Total Load
F(kWht,Y,+j,S) = F(kWh/Ct,Y,+j,S) x F(Ct,Yc+j,S)
Where:
■ F(kWht,yc+j,$) = the forecast for month t, year = 1,...,5 beyond the current year,
yc ,for schedule s.
■ F(kWh/Ct,yC+j,$) = the UPC forecast.
■ F(Ct,yc+j,$) = the customer forecast.
UPC Forecast Methodology
The econometric modeling for UPC is a variation of the "fully integrated" approach
expressed by Faruqui (2000) in the following equation:'
Equation 1.2: Use Per Customer Regression Equation
kWh/Ct,Y,s = aWt,Y + #Zt,Y + Et,Y
The model uses actual historical weather, UPC, and non-weather drivers to estimate the
regression in Equation 1.2. To develop the forecast, normal weather replaces actual
weather (W) along with the forecasted values for the Z variables (Faruqui, pp. 6-7). Here,
W is a vector of heating degree day (HDD) and cooling degree day (CDD) variables; Z is
a vector of non-weather variables; and Et,y is an uncorrelated N(0,a) error term. For non-
weather sensitive schedules, W= 0.
The W variables are HDDs and CDDs. Depending on the rate schedule, the Z variables
may include real average energy price (RAP); the U.S. Federal Reserve Industrial
Production Index (IP); residential natural gas penetration (GAS); non-weather seasonal
6 For schedules representing a single customer, where there is no customer count and for street lighting,
Avista forecasts total load directly without first forecasting UPC.
Faruqui, Ahmad (2000). Making Forecasts and Weather Normalization Work Together, Electric Power
Research Institute, Publication No. 1000546, Tech Review, March 2000.
2025 Natural Gas IRP Appendix 69

dummy variables (SD); trend functions (T); and dummy variables for outliers (OL) and
periods of structural change (SC). RAP is measured as the average annual price
(schedule total revenue divided by schedule total usage) divided by the Consumer Price
Index (CPI), less energy. For most schedules, the only non-weather variables are SD,
SC, and OL. See Table 1.1 for the occurrence RAP and IP.
If the error term appears to be non-white noise, then the forecasting performance of
Equation 1.2 can be improved by converting it into an (ARIMA) "transfer function" model
such that Ct,y = ARIMACt,y(p,d,q)(pk,dk,gk)k. The term p is the autoregressive (AR) order,
d is the differencing order, and q is the (MA) order. The term pk is the order of seasonal
AR terms, dk is the order of seasonal differencing, and qk is the seasonal order of MA
terms. The seasonal values relate to "k," or the frequency of the data, with the current
monthly data set, k = 12.
Certain rate schedules, such as lighting, use simpler regression and smoothing methods
because they offer the best fit for irregular usage without seasonal or weather-related
behavior, are in a long-run steady decline, or are seasonal and unrelated to weather.
Over the 2024-2028 period, Avista defines normal weather for the load forecast as a 20-
year moving average of degree-days taken from the National Oceanic and Atmospheric
Administration's Spokane International Airport data. Normal weather updates only occur
when a full year of new data is available. For example, normal weather for 2018 is the 20-
year average of degree-days for the 1998 to 2017 period; and 2019 is the average of the
1999 to 2018 period. This medium-term forecast uses the 20-year average from the 2004
to 2023 period to develop the 2024 to 2028 forecast.
The choice of a 20-year moving average for defining normal weather reflects several
factors. First, climate research from the National Aeronautics and Space Administration's
(NASA) Goddard Institute for Space Studies (GISS) shows a shift in temperature starting
almost 30 years ago. The GISS research finds summer temperatures in the Northern
Hemisphere increased one degree Fahrenheit above the 1951-1980 reference period;
the increase started roughly 30 years ago in the 1981-1991 period.$An in-house analysis
of temperature in Avista's Spokane/Kootenai service area, using the same 1951-1980
reference period, also reflects an upward shift in temperature starting about 30-years ago.
As provided in ,;napter �D, the longer-term temperature assumption in the IRP uses the
Representative Concentration Pathways (RCP) 8.5 for June, July, August, and
September, and the RCP 4.5 for the remainder of the year.
The second factor in using a 20-year moving average is the volatility of the moving
average as a function of the years used to calculate the average. The 10 and 15-year
moving averages show considerably more year-to-year volatility than the 20-year moving
average. This volatility can obscure longer-term trends and leads to overly sharp changes
8 See Hansen, J.; M. Sato; and R. Ruedy (2013). Global Temperature Update Through 2012,
http://www.nasa.gov/topics/earth/features/2012-temps.htmL
2025 Natural Gas IRP Appendix 70

in forecasted loads when applying the updated definition of normal weather each year.
These sharp changes would also cause excessive volatility in the revenue and earnings
forecasts.
As noted earlier, if non-weather drivers appear in Equation 1 .2, then they must also be in
the five-year forecast used to generate the UPC forecast. The assumption in the five-year
forecast is for RAP to be constant through 2028.
Table '- ""r Models Using Non-Weather Driver Variables
. .
Washington:
Residential Schedule 1 GAS Ratio of natural gas residential schedule 101
customers in WA to electric residential
schedule 1 customers in WA.
Industrial Schedules 11, 21, and 25 IP
Idaho:
Residential Schedule 1 GAS Ratio of natural gas residential schedule 101
customers in ID to electric residential
schedule 1 customers in ID.
Industrial Schedules 11 and 21 IP
The forecasts for GDP reflect the average of forecasts from multiple sources including
the Bloomberg survey of forecasts, the Philadelphia Federal Reserve survey of
forecasters, the Wall Street Journal survey of forecasters and other sources. Averaging
forecasts reduces the systematic errors of a single-source forecast and assumes
macroeconomic factors flow through the UPC in the industrial rate schedules. Figure 1.7
shows the methodology for forecasting IP growth.
*This methodology was used in Idaho, Oregon and Washington for the years 2025-2028
and was calibrated to meet customer expectations and load in the AEG end use forecasts
as discussed in Chapter 3.
2025 Natural Gas IRP Appendix 71

Figure 1.7: Forecasting IP Growth
Average GDP U.S Industrial Production Generate Average, High, and Low
Growth Forecasts: Index(IP)Growth Model: IP Forecast:
•
IMF, FOMC, • Model links year y Forecast annual IP growth
Bloomberg,etc. GDP GDP growth year y IP using the GDP forecast
• Average g
rowth. EI average(the baseline
forecasts out 5- Federal Reserve scenario), a"high"scenario,
yrs. industrial production and a"low"scenario.
index is measure of IP The high and low GDP
growth. forecasts are the annual high
• Forecast out 5-years. and low values from the
sources used to generate the
average GDP growth rate in
each year.
• Apply scenario that makes
most sense given the most
current economic analysis.
• Convert annual growth
scenario to a monthly basis to
project out the monthly level of
the IP.
2025 Natural Gas IRP Appendix 72

Appendix 3.2: Customer Counts
Table 1: Customer Count by State and Class
WA 161,429 161,501 161,573 161,645 161,717 161,789 161,862 161,934 162,006 162,078
ID 80,127 82,131 83,640 85,197 86,722 88,212 89,714 91,198 92,706 94,239
OR 96,768 97,288 97,737 98,188 98,641 99,097 99,554 100,013 100,475 100,938
i
WA 15,227 15,215 15,203 15,191 15,179 15,167 15,155 15,143 15,131 15,119
ID 10,173 10,278 10,370 10,471 10,566 10,664 10,760 10,858 10,955 11,053
OR 12,117 12,133 12,143 12,157 12,168 12,181 12,193 12,206 12,218 12,231
2028 2029 2030
WA 91 91 91 91 91 91 91 91 91 91
ID 66 66 66 66 66 66 66 66 66 66
OR 25 25 25 25 25 25 25 25 25 25
WA 162,150 162,223 162,295 162,367 162,439 162,512 162,584 162,657 162,729 162,802
ID 95,798 97,383 98,993 100,631 102,295 103,987 105,707 107,455 109,232 111,039
OR 101,404 101,872 102,342 102,814 103,288 103,765 104,244 104,725 105,208 105,693
WA 15,107 15,095 15,083 15,071 15,059 15,047 15,035 15,023 15,011 14,999
ID 11,150 11,247 11,344 11,441 11,538 11,636 11,733 11,830 11,927 12,024
OR 12,243 12,255 12,268 12,280 12,292 12,305 12,317 12,329 12,342 12,354
WA 91 91 91 91 91 91 91 91 91 91
ID 66 66 66 661 66 66 66 66 66 66
OR 25 25 25 25 1 25 25 25 25 25 25
2025 Natural Gas IRP Appendix 73

Table 1: Energy Intensity per Customer(Dth)
State 2026 i 2035 2040M
Washington Residential 77.1 73.8 67.0 60.8 55.9
Washington Commercial 497.1 430.8 358.8 299.5 257.1
Washington Industrial 3,221.9 3,133.7 3,011.7 2,913.5 2,846.2
Idaho Residential 81.5 75.4 68.8 63.2 58.7
Idaho Commercial 359.2 345.0 331.2 322.7 322.1
Idaho Industrial 2,894.9 2,846.1 2,757.6 2,683.3 2,628.6
Oregon Residential 56.1 52.6 48.1 43.3 38.7
Oregon Commercial 275.8 264.2 249.6 235.4 219.7
Oregon Industrial 1 2,107.5 1 1,436.4 1 724.9 1 417.7 1 347.7
Figure 1: Energy Intensity per Residential Customer (Dth)
90
L
a) 80
E
° 70
W
u 60
L
°- - 50
40
a' 30
c
L 20 Idaho Residential
10 Oregon Residential
w Washington Residential
Co r- 00 M C N M MTU') w f` 00 M C N c`') LO
N N N N M M M M M M M M M M Iqc* IqtT
C C C C C C C C C C C C C C C C C C C C
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 74

Figure 2: Energy Intensity per Commercial Customer(Dth)
600
L
Q�
500
0
v 400
L
w
a�
0 300
cn �—
c
200
a
Idaho Commercial
100 _Oregon Commercial
w Washington Commercial
CD I` 00 M O N M 11 LO eD f- M M O N M q* LO
N N N N M M M M M M M M M M ' qtqcT 'q q1
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Figure 3: Energy Intensity per Residential Customer(Dth)
3,500
L
E 3,000
0
u 2,500
L
a 2,000
" 1 ,500
a
1 ,000
L
Idaho Industrial
500 —Oregon Industrial
w
Washington Industrial
tD f` M O O � N M Iq LO cA f` M M O N M Iq LO
N N N N M M M M M M M M M M ' 'q 'q 'q 'q
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 75

MONTHLY HEATING DEGREE DAYS - RCP 4.5
Klamath Falls
OctD-
2026 1,046 859 821 671 487 345 237 273 397 602 856 1,079
2027 1,046 858 821 671 486 344 237 273 397 602 856 1,078
2028 1,045 892 820 670 486 344 237 273 397 602 855 1,077
2029 1,044 857 820 670 486 344 237 273 397 601 855 1,077
2030 1,044 857 819 669 485 344 237 272 396 601 854 1,076
2031 1,043 856 819 669 485 344 237 272 396 600 854 1,076
2032 1,043 890 819 669 485 343 236 272 396 600 853 1,075
2033 1,042 855 818 668 485 343 236 272 396 600 853 1,074
2034 1,041 855 818 668 484 343 236 272 395 599 852 1,074
2035 1,041 854 817 668 484 343 236 272 395 599 852 1,073
2036 1,040 888 817 667 484 343 236 272 395 599 851 1,072
2037 1,040 853 816 667 483 342 236 271 395 598 851 1,072
2038 1,039 853 816 666 483 342 236 271 395 598 850 1,071
2039 1,038 853 815 666 483 342 235 271 394 598 850 1,071
2040 1,038 886 815 666 483 342 235 271 394 597 849 1,070
2041 1,037 852 814 665 482 342 235 271 394 597 849 1,069
2042 1,037 851 814 665 482 341 235 271 394 597 848 1,069
2043 1,036 851 813 664 482 341 235 270 393 596 848 1,068
2044 1,035 884 813 664 481 341 235 270 393 596 847 1,067
2045 1,035 850 812 664 481 341 235 270 393 596 847 1,067
La Grande
2026 1,009 832 740 584 400 264 193 224 346 545 784 1,030
2027 1,008 832 739 583 399 263 993 224 345 545 783 1,029
2028 1,007 857 738 583 399 263 193 224 345 544 782 1,028
2029 1,006 830 737 582 398 263 193 224 345 544 781 1,027
2030 1,005 829 737 581 398 263 193 223 344 543 781 1,026
2031 1,004 828 736 581 398 262 192 223 344 543 780 1,025
2032 1,003 853 735 580 397 262 192 223 343 542 779 1,024
2033 1,002 826 734 580 397 262 192 223 343 541 778 1 ,023
2034 1,001 825 733 579 396 261 192 222 343 541 777 1 ,022
2035 1,000 825 733 578 396 261 192 222 342 540 776 1 ,021
2036 999 849 732 578 395 261 191 222 342 540 776 1,019
2037 998 823 731 577 395 261 191 222 342 539 775 1,018
2038 997 822 730 576 395 260 191 221 341 539 774 1,017
2039 995 821 730 576 394 260 191 221 341 538 773 1,016
2040 994 846 729 575 394 260 191 221 341 537 772 1,015
2041 993 819 728 575 393 260 190 221 340 537 772 1,014
2025 Natural Gas IRP Appendix 76

2042 992 818 727 574 393 259 190 221 340 536 771 1,013
2043 991 818 726 573 393 259 190 220 339 536 770 1,012
2044 990 842 726 573 392 259 190 220 339 535 769 1,011
2045 989 816 725 572 392 258 190 220 339 535 768 1,010
Medford
Year Jan • • • •
2026 762 608 551 423 285 176 79 97 201 374 600 794
2027 762 607 550 422 285 176 79 97 200 373 599 793
2028 761 629 550 422 284 176 79 97 200 373 598 792
2029 760 606 549 421 284 176 79 96 200 372 598 791
2030 759 605 548 421 284 175 79 96 200 372 597 790
2031 758 605 548 420 283 175 79 96 200 372 596 790
2032 758 626 547 420 283 175 79 96 199 371 596 789
2033 757 603 547 420 283 175 79 96 199 371 595 788
2034 756 603 546 419 283 175 79 96 199 370 594 787
2035 755 602 546 419 282 175 79 96 199 370 594 786
2036 754 623 545 418 282 174 79 96 199 370 593 785
2037 754 601 544 418 282 174 79 96 198 369 592 784
2038 753 600 544 417 281 174 78 95 198 369 592 784
2039 752 600 543 417 281 174 78 95 198 368 591 783
2040 751 621 543 416 281 174 78 95 198 368 591 782
2041 750 598 542 416 280 173 78 95 198 368 590 781
2042 750 598 541 416 280 173 78 95 197 367 589 780
2043 749 597 541 415 280 173 78 95 197 367 589 779
2044 748 618 540 415 280 173 78 95 197 366 588 779
2045 747 596 540 414 279 173 78 95 197 366 587 778
Roseburg
t26 671 561 522 414 283 180 111 114 192 332 533 696
2027 670 560 521 413 282 180 111 114 192 331 533 695
2028 669 579 520 412 282 179 111 114 191 331 532 693
2029 668 558 519 411 281 179 111 114 191 330 531 692
2030 667 557 519 411 281 179 110 113 191 330 530 691
2031 666 557 518 410 280 179 110 113 191 329 529 690
2032 665 576 517 409 280 178 110 113 190 328 528 689
2033 663 555 516 409 279 178 110 113 190 328 527 688
2034 662 554 515 408 279 178 110 113 190 327 526 687
2035 661 553 514 407 278 177 109 112 189 327 525 685
2036 660 572 513 407 278 177 109 112 189 326 525 684
2037 659 551 512 406 277 177 109 112 189 326 524 683
2038 658 550 512 405 277 176 109 112 188 325 523 682
2025 Natural Gas IRP Appendix 77

2039 657 549 511 405 276 176 109 112 188 325 522 681
2040 656 568 510 404 276 176 109 111 188 324 521 680
2041 655 547 509 403 276 176 108 111 187 324 520 679
2042 653 546 508 403 275 175 108 111 187 323 519 677
2043 652 545 507 402 275 175 108 111 187 322 518 676
2044 651 564 507 401 274 175 108 111 186 322 518 675
2045 650 544 506 401 274 174 108 111 186 321 517 674
Spokane
2026 1,087 931 777 565 342 213 101 118 255 535 865 1,130
2027 1,085 929 776 564 341 212 101 118 254 534 863 1,128
2028 1,083 955 774 563 341 212 101 118 254 533 862 1,126
2029 1,081 926 773 562 340 212 101 118 253 532 860 1,124
2030 1,079 924 772 561 339 211 100 118 253 531 859 1,122
2031 1,077 923 770 560 339 211 100 117 252 530 857 1,120
2032 1,075 949 769 559 338 210 100 117 252 529 856 1,118
2033 1,073 919 768 558 338 210 100 117 252 528 854 1,116
2034 1,072 918 766 557 337 210 100 117 251 527 853 1,114
2035 1,070 916 765 556 336 209 100 117 251 526 851 1,112
2036 1,068 942 764 555 336 209 99 116 250 525 850 1,110
2037 1,066 913 762 554 335 209 99 116 250 524 848 1,108
2038 1,064 911 761 553 335 208 99 116 249 523 847 1,106
2039 1,062 909 759 552 334 208 99 116 249 522 845 1,104
2040 1,060 935 758 551 333 208 99 115 248 521 844 1,102
2041 1,058 906 757 550 333 207 98 115 248 521 842 1,101
2042 1,056 905 755 549 332 207 98 115 248 520 841 1 ,099
2043 1,054 903 754 548 332 206 98 115 247 519 839 1 ,097
2044 1,053 929 753 547 331 206 98 115 247 518 838 1 ,095
2045 1,051 900 751 546 331 206 98 114 246 517 836 1 ,093
MONTHLY HEATING DEGREE DAYS - RCP 6.5
Klamath Falls
• Mar Apr • -
2026 1,045 858 821 670 486 344 237 273 397 602 856 1,078
2027 1,044 857 820 670 486 344 237 273 396 601 854 1,076
2028 1,043 890 819 669 485 343 236 272 396 600 853 1 ,075
2029 1 1,041 855 1 817 668 1 484 343 236 272 395 599 852 1 ,074
2030 1,040 854 816 667 484 342 236 271 395 599 851 1,072
2031 1,039 853 815 666 483 342 236 271 394 598 850 1,071
2032 1,037 885 814 665 482 342 235 271 394 597 849 1,069
2033 1,036 850 813 664 482 341 235 270 393 596 848 1,068
2025 Natural Gas IRP Appendix 78

2034 1,034 849 812 663 481 341 235 270 393 595 847 1,067
2035 1,033 848 811 663 480 340 234 270 392 595 845 1,065
2036 1,032 881 810 662 480 340 234 269 392 594 844 1,064
2037 1,030 846 809 661 479 339 234 269 391 593 843 1,062
2038 1,029 845 808 660 479 339 233 269 391 592 842 1,061
2039 1,028 844 807 659 478 338 233 268 390 592 841 1,060
2040 1,026 876 806 658 477 338 233 268 390 591 840 1,058
2041 1,025 841 805 657 477 338 232 268 389 590 839 1,057
2042 1,024 840 804 656 476 337 232 267 389 589 838 1,055
2043 1,022 839 803 656 475 337 232 267 388 588 837 1,054
2044 1,021 872 802 655 475 336 232 267 388 588 836 1,053
2045 1,020 837 800 654 474 336 231 266 387 587 834 1,051
La Grande
2026 1,009 832 739 584 399 264 193 224 345 545 784 1 ,030
2027 1,007 831 738 583 399 263 193 224 345 544 782 1,028
2028 1,006 855 737 582 398 263 193 224 344 543 781 1,027
2029 1,004 828 736 581 398 262 192 223 344 543 780 1,025
2030 1,003 827 735 580 397 262 192 223 343 542 779 1,023
2031 1,001 826 733 579 396 261 192 222 343 541 777 1,022
2032 999 850 732 578 396 261 192 222 342 540 776 1,020
2033 998 823 731 577 395 261 191 222 342 539 775 1,019
2034 996 822 730 576 395 260 191 221 341 538 774 1,017
2035 995 820 729 575 394 260 191 221 341 538 773 1,015
2036 993 845 728 575 393 259 190 221 340 537 771 1,014
2037 992 818 727 574 393 259 190 220 340 536 770 1 ,012
2038 990 816 725 573 392 259 190 220 339 535 769 1 ,011
2039 988 815 724 572 391 258 189 220 338 534 768 1,009
2040 987 840 723 571 391 258 189 219 338 533 766 1,007
2041 985 813 722 570 390 257 189 219 337 532 765 1,006
2042 984 811 721 569 390 257 189 219 337 532 764 1,004
2043 982 810 720 568 389 257 188 218 336 531 763 1,003
2044 981 835 719 567 388 256 188 218 336 530 762 1,001
2045 979 808 718 566 388 256 188 218 335 529 761 1,000
Medford
� -
2026 762 607 550 422 285 176 79 97 201 373 599 793
2027 760 606 549 422 284 176 79 96 200 373 598 792
2028 759 627 548 421 284 175 79 96 200 372 597 790
2029 757 604 547 420 283 175 79 96 199 371 596 789
2030 756 603 546 419 283 175 79 96 199 370 594 787
2025 Natural Gas IRP Appendix 79

2031 755 602 545 418 282 174 79 96 199 370 593 786
2032 753 622 544 417 281 174 79 96 198 369 592 784
2033 752 599 543 417 281 174 78 95 198 368 591 783
2034 750 598 542 416 280 173 78 95 197 368 590 781
2035 749 597 541 415 280 173 78 95 197 367 589 780
2036 747 618 540 414 279 173 78 95 197 366 588 778
2037 746 595 539 414 279 172 78 95 196 365 587 777
2038 745 594 538 413 278 172 78 94 196 365 585 775
2039 743 593 537 412 278 172 77 94 196 364 584 774
2040 742 613 536 411 277 171 77 94 195 363 583 772
2041 740 590 535 410 277 171 77 94 195 363 582 771
2042 739 589 534 410 276 171 77 94 195 362 581 769
2043 738 588 533 409 276 170 77 94 194 361 580 768
2044 736 609 532 408 275 170 77 93 194 361 579 766
2045 735 586 531 407 275 170 77 93 193 360 578 765
Roseburg
L . •
2026 671 561 522 413 282 180 111 114 192 332 533 695
2027 669 559 520 412 282 180 111 114 192 331 532 694
2028 668 578 519 411 281 179 111 114 191 330 530 692
2029 666 557 518 410 280 179 110 113 191 329 529 690
2030 664 555 517 409 280 178 110 113 190 328 528 689
2031 663 554 515 408 279 178 110 113 190 328 527 687
2032 661 573 514 407 278 177 109 112 189 327 525 685
2033 660 551 513 406 278 177 109 112 189 326 524 684
2034 658 550 512 405 277 177 109 112 188 325 523 682
2035 656 549 511 404 276 176 109 112 188 324 522 680
2036 655 567 509 403 276 176 108 111 187 324 520 679
2037 653 546 508 402 275 175 108 111 187 323 519 677
2038 652 545 507 401 274 175 108 111 187 322 518 676
2039 650 544 506 401 274 174 108 111 186 321 517 674
2040 649 562 504 400 273 174 107 110 186 321 515 672
2041 647 541 503 399 272 174 107 110 185 320 514 671
2042 645 540 502 398 272 173 107 110 185 319 513 669
2043 644 538 501 397 271 173 107 109 184 318 512 668
2044 642 557 500 396 270 172 106 109 184 318 511 666
2045 641 536 498 395 270 172 106 109 183 317 509 664
Spokane
7202026 1,087 931 777 564 342 213 101 118 255 535 865 1,130
27 1,085 929 776 563 341 212 101 118 254 534 863 1,128
2025 Natural Gas IRP Appendix 80

2028 1,083 955 774 562 341 212 101 118 254 532 861 1,126
2029 1,080 925 773 561 340 211 101 118 253 531 860 1,124
2030 1,078 923 771 560 339 211 100 117 253 530 858 1,121
2031 1,076 922 770 559 339 211 100 117 252 529 856 1,119
2032 1,074 947 768 558 338 210 100 117 252 528 855 1,117
2033 1,072 918 767 557 337 210 100 117 251 527 853 1,115
2034 1,070 916 765 556 337 209 100 117 251 526 851 1,113
2035 1,068 914 764 555 336 209 99 116 250 525 850 1,111
2036 1,066 940 762 554 335 209 99 116 250 524 848 1,108
2037 1,064 911 761 553 335 208 99 116 249 523 846 1,106
2038 1,062 909 759 551 334 208 99 116 249 522 845 1,104
2039 1,060 907 758 550 333 207 99 115 248 521 843 1,102
2040 1,058 933 756 549 333 207 98 115 248 520 842 1,100
2041 1,056 904 755 548 332 207 98 115 247 519 840 1,098
2042 1,053 902 753 547 331 206 98 115 247 518 838 1,096
2043 1,051 900 752 546 331 206 98 115 246 517 837 1,093
2044 1,049 926 750 545 330 205 98 114 246 516 835 1,091
2045 1,047 897 749 544 329 205 97 114 245 515 833 1,089
MONTHLY HEATING DEGREE DAYS - RCP 8.5
Klamath Falls
2026 1,045 858 820 670 486 344 237 273 397 601 855 1,077
2027 1,043 856 818 669 485 343 236 272 396 600 853 1,075
2028 1,040 888 817 667 484 343 236 272 395 599 851 1,073
2029 1,038 852 815 666 483 342 235 271 394 598 850 1,070
2030 1,036 851 813 664 482 341 235 270 393 596 848 1,068
2031 1,034 849 812 663 481 340 234 270 393 595 846 1,066
2032 1,032 881 810 662 480 340 234 269 392 594 844 1,064
2033 1,030 845 808 660 479 339 233 269 391 593 843 1,062
2034 1,028 844 807 659 478 338 233 268 390 591 841 1,059
2035 1,025 842 805 658 477 338 233 268 389 590 839 1,057
2036 1,023 874 803 656 476 337 232 267 389 589 837 1,055
2037 1,021 838 802 655 475 336 232 267 388 588 836 1,053
2038 1,019 837 800 654 474 336 231 266 387 587 834 1,051
2039 1,017 835 798 652 473 335 231 265 386 585 832 1 ,048
2040 1,015 867 797 651 472 334 230 265 385 584 831 1 ,046
2041 1,013 831 795 650 471 334 230 264 385 583 829 1 ,044
2042 1,011 830 793 648 470 333 229 264 384 582 827 1,042
2043 1,009 828 792 647 469 332 229 263 383 581 825 1,040
2044 1,006 860 790 646 468 331 228 263 382 579 824 1 ,038
2045 1,004 825 789 644 467 331 228 262 381 578 822 1,036
2025 Natural Gas IRP Appendix 81

La Grande
2026 1,008 832 739 583 399 263 193 224 345 545 783 1,029
2027 1,006 830 737 582 398 263 193 224 345 544 782 1,027
2028 1,004 854 736 581 398 262 192 223 344 543 780 1,025
2029 1,002 826 734 580 397 262 192 223 343 541 778 1,023
2030 1,000 825 733 578 396 261 192 222 342 540 777 1,021
2031 998 823 731 577 395 261 191 222 342 539 775 1,019
2032 996 847 730 576 394 260 191 221 341 538 773 1,017
2033 994 820 728 575 394 260 190 221 340 537 772 1,014
2034 992 818 727 574 393 259 190 220 340 536 770 1,012
2035 990 816 725 572 392 259 190 220 339 535 769 1,010
2036 988 840 724 571 391 258 189 219 338 534 767 1,008
2037 985 813 722 570 390 257 189 219 337 533 765 1,006
2038 983 811 721 569 389 257 188 219 337 531 764 1,004
2039 981 809 719 568 389 256 188 218 336 530 762 1,002
2040 979 833 718 567 388 256 188 218 335 529 761 1,000
2041 977 806 716 565 387 255 187 217 335 528 759 998
2042 975 804 715 564 386 255 187 217 334 527 757 996
2043 973 803 713 563 385 254 187 216 333 526 756 994
2044 971 827 712 562 385 254 186 216 333 525 754 991
2045 969 799 710 561 384 253 186 215 332 524 753 989
Medford Wmp Oct Nov Dec
Year Jan]FM�Mw Apr Majl�F-Jul
2026 761 607 550 422 284 176 79 97 200 373 598 792
2027 759 605 548 421 284 175 79 96 200 372 597 790
2028 757 625 547 420 283 175 79 96 199 371 595 788
2029 755 602 545 418 282 174 79 96 199 370 594 786
2030 753 600 544 417 281 174 78 95 198 369 592 784
2031 751 599 542 416 281 174 78 95 198 368 590 782
2032 749 619 541 415 280 173 78 95 197 367 589 779
2033 747 595 539 414 279 173 78 95 197 366 587 777
2034 745 594 538 413 278 172 78 94 196 365 585 775
2035 743 592 536 412 278 172 77 94 195 364 584 773
2036 740 612 535 410 277 171 77 94 195 363 582 771
2037 738 589 533 409 276 171 77 94 194 362 581 769
2038 736 587 532 408 275 170 77 93 194 361 579 767
2039 734 586 530 407 274 170 77 93 193 360 577 764
2040 732 606 529 406 274 169 76 93 193 359 576 762
2041 730 582 528 405 273 169 76 93 192 358 574 760
2042 728 581 526 404 272 168 76 92 192 357 573 758
2025 Natural Gas IRP Appendix 82

2043 726 579 525 403 271 168 76 92 191 356 571 756
2044 724 599 523 402 271 167 76 92 191 355 569 754
2045 722 576 522 400 270 167 75 92 190 354 568 752
Roseburg
72026 670 560 521 413 282 180 111 114 192 331 533 695
027 668 559 520 412 281 179 111 114 191 330 531 693
2028 666 577 518 410 280 179 110 113 191 329 529 690
2029 664 555 516 409 280 178 110 113 190 328 528 688
2030 662 553 515 408 279 178 110 113 189 327 526 686
2031 660 552 513 407 278 177 109 112 189 326 524 684
2032 658 570 512 405 277 176 109 112 188 325 523 682
2033 656 548 510 404 276 176 109 112 188 324 521 680
2034 654 547 508 403 275 175 108 111 187 323 519 678
2035 652 545 507 401 274 175 108 111 187 322 518 675
2036 650 563 505 400 273 174 108 110 186 321 516 673
2037 648 541 504 399 273 174 107 110 185 320 515 671
2038 646 540 502 398 272 173 107 110 185 319 513 669
2039 644 538 501 396 271 173 107 109 184 318 511 667
2040 642 556 499 395 270 172 106 109 184 317 510 665
2041 640 535 497 394 269 172 106 109 183 316 508 663
2042 638 533 496 393 268 171 106 108 182 315 507 661
2043 636 531 494 392 268 171 105 108 182 314 505 659
2044 634 550 493 390 267 170 105 108 181 313 504 657
2045 632 528 491 389 266 169 105 107 181 312 502 655
Spokane
-
Year
2026 1,087 930 777 564 342 213 101 118 255 534 865 1,130
2027 1,084 929 775 563 341 212 101 118 254 533 863 1,128
2028 1,082 954 774 562 340 212 101 118 254 532 861 1,125
2029 1,080 925 772 561 340 211 100 118 253 531 859 1,123
2030 1,077 923 770 560 339 211 100 117 253 530 857 1,120
2031 1,075 921 769 558 338 210 100 117 252 529 856 1,118
2032 1,073 946 767 557 338 210 100 117 251 528 854 1,116
2033 1,071 917 766 556 337 210 100 117 251 527 852 1,113
2034 1,068 915 764 555 336 209 99 116 250 526 850 1,111
2035 1,066 913 762 554 335 209 99 116 250 524 848 1,109
2036 1,064 939 761 553 335 208 99 116 249 523 847 1,106
2037 1,062 909 759 551 334 208 99 116 249 522 845 1,104
2038 1,059 907 758 550 333 207 99 115 248 521 843 1,102
2039 1,057 905 756 549 333 207 98 115 248 520 841 1,099
2025 Natural Gas IRP Appendix 83

2040 1,055 931 754 548 332 207 98 115 247 519 839 1,097
2041 1,053 902 753 547 331 206 98 115 247 518 838 1,095
2042 1,051 900 751 546 330 206 98 114 246 517 836 1,093
2043 1,048 898 750 545 330 205 98 114 246 516 834 1,090
2044 1,046 923 748 543 329 205 97 114 245 515 832 1,088
2045 1,044 894 747 542 328 204 97 114 245 514 831 1,086
MONTHLY HEATING DEGREE DAYS - 20 YEAR AVERAGE
Klamath Falls
2026 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2027 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2028 1,047 892 822 671 487 345 237 273 397 603 857 1,079
2029 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2030 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2031 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2032 1,047 892 822 671 487 345 237 273 397 603 857 1,079
2033 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2034 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2035 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2036 1,047 892 822 671 487 345 237 273 397 603 857 1,079
2037 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2038 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2039 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2040 1,047 892 822 671 487 345 237 273 397 603 857 1,079
2041 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2042 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2043 1,047 859 822 671 487 345 237 273 397 603 857 1,079
2044 1,047 892 822 671 487 345 237 273 397 603 857 1,079
2045 1,047 859 822 671 487 345 237 273 397 603 857 1,079
La Grande
2026 1,010 833 740 585 400 264 194 225 346 546 785 1 ,032
2027 1,010 833 740 585 400 264 194 225 346 546 785 1 ,032
2028 1,010 860 740 585 400 264 194 225 346 546 785 1,032
2029 1,010 833 740 585 400 264 194 225 346 546 785 1 ,032
2030 1,010 833 740 585 400 264 194 225 346 546 785 1 ,032
2031 1,010 833 740 585 400 264 194 225 346 546 785 1 ,032
2032 1,010 860 740 585 400 264 194 225 346 546 785 1 ,032
2033 1,010 833 740 585 400 264 194 225 346 546 785 1 ,032
2034 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2025 Natural Gas IRP Appendix 84

2035 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2036 1,010 860 740 585 400 264 194 225 346 546 785 1,032
2037 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2038 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2039 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2040 1,010 860 740 585 400 264 194 225 346 546 785 1,032
2041 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2042 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2043 1,010 833 740 585 400 264 194 225 346 546 785 1,032
2044 1,010 860 740 585 400 264 194 225 346 546 785 1,032
2045 1,010 833 740 585 400 264 194 225 346 546 785 1,032
Medford
2026 763 609 551 423 285 176 80 97 201 374 600 795
2027 763 609 551 423 285 176 80 97 201 374 600 795
2028 763 631 551 423 285 176 80 97 201 374 600 795
2029 763 609 551 423 285 176 80 97 201 374 600 795
2030 763 609 551 423 285 176 80 97 201 374 600 795
2031 763 609 551 423 285 176 80 97 201 374 600 795
2032 763 631 551 423 285 176 80 97 201 374 600 795
2033 763 609 551 423 285 176 80 97 201 374 600 795
2034 763 609 551 423 285 176 80 97 201 374 600 795
2035 763 609 551 423 285 176 80 97 201 374 600 795
2036 763 631 551 423 285 176 80 97 201 374 600 795
2037 763 609 551 423 285 176 80 97 201 374 600 795
2038 763 609 551 423 285 176 80 97 201 374 600 795
2039 763 609 551 423 285 176 80 97 201 374 600 795
2040 763 631 551 423 285 176 80 97 201 374 600 795
2041 763 609 551 423 285 176 80 97 201 374 600 795
2042 763 609 551 423 285 176 80 97 201 374 600 795
2043 763 609 551 423 285 176 80 97 201 374 600 795
2044 763 631 551 423 285 176 80 97 201 374 600 795
2045 763 609 551 423 285 176 80 97 201 374 600 795
Roseburg
Year Jan • mar AprM§L& Sep •
2026 672 562 523 414 283 1 180 111 114 192 332 534 697
2027 672 562 523 414 283 180 111 114 192 332 534 697
2028 672 582 523 414 283 180 111 114 192 332 534 697
2029 672 562 523 414 283 180 111 114 192 332 534 697
2030 672 562 523 414 283 180 111 114 192 332 534 697
2031 672 562 523 414 283 180 111 114 192 332 534 697
2025 Natural Gas IRP Appendix 85

2032 672 582 523 414 283 180 111 114 192 332 534 697
2033 672 562 523 414 283 180 111 114 192 332 534 697
2034 672 562 523 414 283 180 111 114 192 332 534 697
2035 672 562 523 414 283 180 111 114 192 332 534 697
2036 672 582 523 414 283 180 111 114 192 332 534 697
2037 672 562 523 414 283 180 111 114 192 332 534 697
2038 672 562 523 414 283 180 111 114 192 332 534 697
2039 672 562 523 414 283 180 111 114 192 332 534 697
2040 672 582 523 414 283 180 111 114 192 332 534 697
2041 672 562 523 414 283 180 111 114 192 332 534 697
2042 672 562 523 414 283 180 111 114 192 332 534 697
2043 672 562 523 414 283 180 111 114 192 332 534 697
2044 672 582 523 414 283 180 111 114 192 332 534 697
2045 672 562 523 414 283 180 111 114 192 332 534 697
Spokane
2026 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2027 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2028 1,089 960 779 566 343 213 101 119 255 536 866 1,132
2029 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2030 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2031 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2032 1,089 960 779 566 343 213 101 119 255 536 866 1,132
2033 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2034 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2035 1,089 932 779 566 343 213 101 119 255 536 866 1 ,132
2036 1,089 960 779 566 343 213 101 119 255 536 866 1 ,132
2037 1,089 932 779 566 343 213 101 119 255 536 866 1 ,132
2038 1,089 932 779 566 343 213 101 119 255 536 866 1 ,132
2039 1,089 932 779 566 343 213 101 119 255 536 866 1 ,132
2040 1,089 960 779 566 343 213 101 119 255 536 866 1,132
2041 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2042 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2043 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2044 1,089 960 779 566 343 213 101 119 255 536 866 1,132
2045 1,089 932 779 566 343 213 101 119 255 536 866 1,132
2025 Natural Gas IRP Appendix 86

Annual Load Net of Energy Efficiency (Thousand Dekatherms)
*All cases not listed below match the PRS
r Washingtoll
UT ora"rn s
• • Transport
2026 10,377 8,823 20,307 2,606 3,181
2027 10,401 8,749 20,063 2,593 3,159
2028 10,396 8,661 19,695 2,580 3,137
2029 10,389 8,545 19,216 2,566 3,114
2030 10,373 8,441 18,760 2,551 3,090
2031 10,321 8,320 18,239 2,534 3,066
2032 10,319 8,224 17,808 2,517 3,041
2033 10,289 8,102 17,335 2,500 3,017
2034 10,286 7,993 16,910 2,483 2,994
2035 10,325 7,922 16,558 2,467 2,972
2036 10,364 7,853 16,203 2,452 2,952
2037 10,333 7,734 15,777 2,439 2,936
2038 10,345 7,614 15,393 2,428 2,921
2039 10,327 7,479 14,975 2,417 2,909
2040 10,363 7,379 14,644 2,407 2,897
2041 10,398 7,266 14,331 2,399 2,886
2042 10,391 7,137 13,970 2,391 2,878
2043 10,455 7,025 13,717 2,383 2,869
2044 10,515 6,928 13,468 2,375 2,860
2045 10,565 6,816 13,223 2,368 2,852
Year High Electrification High Growth on Gas System
Idaho Oregon Washington Idaho Oregon
2026 10,377 8,823 20,307 10,850 9,155 20,596
2027 10,401 8,748 19,877 10,923 9,213 20,592
2028 10,282 8,436 18,976 11,018 9,271 20,467
2029 9,833 8,016 17,624 11,050 9,241 20,038
2030 9,401 7,586 16,384 11,083 9,230 19,645
2031 8,942 7,195 15,141 11,105 9,221 19,230
2032 8,528 6,792 14,007 11,165 9,225 18,880
2033 8,053 6,347 12,816 11,177 9,208 18,454
2034 7,590 5,899 11,688 11,223 9,199 18,086
2035 7,187 5,528 10,690 11,288 9,252 17,752
2036 6,831 5,172 9,783 11,380 9,326 17,459
2037 6,325 4,711 8,752 11,404 9,345 17,101
2038 5,794 4,207 7,701 11,469 9,354 16,782
2039 5,266 3,682 6,703 11,532 9,364 16,471
2025 Natural Gas IRP Appendix 87

2040 4,742 3,179 5,766 11,642 9,411 16,233
2041 4,188 2,633 4,851 11,716 9,444 15,962
2042 3,614 2,074 3,960 11,802 9,488 15,732
2043 3,041 1,446 3,119 11,917 9,512 15,545
2044 2,511 854 2,360 12,058 9,593 15,410
2045 1,888 190 1,562 12,155 9,649 15,238
Year Hybrid Heating Initiative i . .
Oregon Washington Idaho • - . .
2026 710,377 8,823 20,307 10,377 8,823 20,605
2027 10,401 8,749 20,063 10,401 8,749 20,557
2028 10,339 8,613 19,633 10,396 8,661 20,392
2029 10,271 8,453 19,088 10,389 8,545 20,105
2030 10,192 8,296 18,563 10,373 8,441 19,824
2031 10,073 8,129 17,970 10,321 8,320 19,493
2032 10,003 7,982 17,464 10,319 8,224 19,217
2033 9,901 7,806 16,911 10,289 8,102 18,915
2034 9,821 7,641 16,402 10,286 7,993 18,640
2035 9,782 7,515 15,962 10,325 7,922 18,415
2036 9,743 7,392 15,520 10,364 7,853 18,190
2037 9,629 7,214 14,998 10,333 7,734 17,921
2038 9,549 7,031 14,508 10,345 7,614 17,670
2039 9,438 6,830 13,981 10,327 7,479 17,396
2040 9,375 6,661 13,534 10,363 7,379 17,182
2041 9,305 6,476 13,096 10,398 7,266 16,984
2042 9,192 6,272 12,607 10,391 7,137 16,750
2043 9,142 6,075 12,216 10,455 7,025 16,593
2044 9,093 5,894 11,832 10,515 6,928 16,437
2045 9,020 5,688 11,435 10,565 6,816 16,289
Year Low Natural Gas Use 19 No Growth
Idaho OregonERWashington Idaho Oregon Washington
2026 10,112 8,606 20,366 10,377 8,823 20,058
2027 10,026 8,526 20,300 10,401 8,645 19,581
2028 9,958 8,450 20,117 10,396 8,461 18,999
2029 9,843 8,297 19,617 10,389 8,248 18,323
2030 9,722 8,159 19,153 10,373 8,049 17,684
2031 9,589 8,020 18,666 10,321 7,836 16,998
2032 9,486 7,888 18,242 10,319 7,649 16,412
2033 9,339 7,734 17,744 10,289 7,439 15,799
2034 9,217 7,583 17,299 10,286 7,244 15,242
2035 9,109 7,478 16,887 10,325 7,084 14,764
2036 9,020 7,386 16,513 10,364 6,929 14,295
2025 Natural Gas IRP Appendix 88

2037 8,875 7,243 16,074 10,333 6,728 13,773
2038 8,761 7,085 15,670 10,345 6,529 13,298
2039 8,647 6,924 15,273 10,327 6,318 12,802
2040 8,566 6,787 14,945 10,363 6,139 12,392
2041 8,458 6,635 14,585 10,398 5,951 12,008
2042 8,360 6,480 14,256 10,391 5,748 11,590
2043 8,281 6,306 13,967 10,455 5,565 11,273
2044 8,219 6,164 13,720 10,515 5,394 10,966
2045 8,127 5,998 13,435 10,565 5,216 10,671
Wdaho O Oregon
2026 10,376 8,818 20,304 10,375 8,813 20,302
2027 10,399 8,739 20,058 10,396 8,730 20,053
2028 10,392 8,647 19,688 10,388 8,632 19,680
2029 10,383 8,525 19,206 10,378 8,506 19,196
2030 10,366 8,417 18,748 10,360 8,393 18,735
2031 10,313 8,291 18,224 10,304 8,263 18,210
2032 10,310 8,191 17,792 10,300 8,158 17,775
2033 10,278 8,065 17,316 10,268 8,027 17,298
2034 10,274 7,951 16,890 10,262 7,910 16,869
2035 10,311 7,875 16,535 10,298 7,829 16,513
2036 10,349 7,803 16,179 10,334 7,752 16,155
2037 10,317 7,678 15,752 10,301 7,623 15,726
2038 10,327 7,555 15,366 10,310 7,495 15,339
2039 10,309 7,415 14,946 10,290 7,352 14,918
2040 10,343 7,311 14,614 10,322 7,243 14,584
2041 10,376 7,194 14,300 10,355 7,122 14,268
2042 10,368 7,060 13,937 10,345 6,984 13,905
2043 10,431 6,944 13,684 10,406 6,864 13,650
2044 10,489 6,843 13,433 10,463 6,759 13,398
2045 10,538 6,727 13,187 10,511 6,639 13,150
Year Average Case Weather
Idaho Oregon Washington
2026 10,868 10,609 19,454
2027 10,990 10,584 19,361
2028 11,147 10,596 19,342
2029 11,244 10,511 19,157
2030 11,359 10,467 19,042
2031 11,469 10,419 18,920
2032 11,627 10,418 18,877
2033 11,683 10,315 18,665
2025 Natural Gas IRP Appendix 89

2034 11,788 10,260 18,539
2035 11,895 10,202 18,418
2036 12,059 10,194 18,390
2037 12,124 10,084 18,211
2038 12,246 10,024 18,124
2039 12,372 9,962 18,050
2040 12,554 9,950 18,064
2041 12,627 9,834 17,921
2042 12,758 9,767 17,874
2043 12,888 9,699 17,827
2044 13,077 9,680 17,872
2045 13,151 9,569 17,758
2025 Natural Gas IRP Appendix 90

AEG.I,
Proudly part of **ICF
AVISTA NATURAL GAS
CONSERVATION POTENTIAL
ASSESSMENT FOR 2026-2045
Ei
Prepared for:Avista Corporation
By:Applied Energy Group, Inc., proudly part of ICF
Date: February 28,2025
Key Contact:Andy Hudson I Phone#[phone]
2025 Natural Gas IRP Appendix 91

Avista Natural Gas Conservation Potential Assessment for 2026-2045
This work was performed by
Applied Energy Group, Inc. (AEG)
2300 Clayton Road, Suite 1370
Concord, CA 94520
Project Director: E. Morris
Project Manager: A. Hudson
Project Team: K.Walter F. Nguyen
T.Williams C.Lee
L.Tang
Applied Energy Group,Inc.,proudly part of ICF 2 of 105
2025 Natural Gas IRP Appendix 92

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Contents
1 1 Introduction.................................................................................................................8
Summary of Report Contents ................................................................................................................9
Abbreviations and Acronyms...............................................................................................................10
21 Energy Efficiency Analysis Approach and Development................................................ 12
Overview of Analysis Approach............................................................................................................12
DataDevelopment ..............................................................................................................................19
DataApplication..................................................................................................................................21
3 1 Energy Efficiency Market Characterization ................................................................... 27
EnergyUse Summary...........................................................................................................................27
ResidentialSector...............................................................................................................................28
CommercialSector.............................................................................................................................33
IndustrialSector..................................................................................................................................39
4 1 Baseline Projection...................................................................................................... 42
Overall Baseline Projection..................................................................................................................42
ResidentialSector...............................................................................................................................44
CommercialSector.............................................................................................................................46
IndustrialSector..................................................................................................................................48
5 1 Conservation Potential................................................................................................ 50
Washington Overall Energy Efficiency Potential...................................................................................50
Idaho Overall Energy Efficiency Potential.............................................................................................52
6 1 Sector-Level Energy Efficiency Potential....................................................................... 54
ResidentialSector...............................................................................................................................54
CommercialSector.............................................................................................................................59
IndustrialSector..................................................................................................................................64
7 1 Demand Response Potential........................................................................................ 70
StudyApproach...................................................................................................................................70
MarketCharacterization......................................................................................................................70
BaselineForecast................................................................................................................................71
Characterize Demand Response Program Options..............................................................................73
DRPotential Results............................................................................................................................75
A I Oregon Low-Income Conservation Potential................................................................. 81
Background.........................................................................................................................................81
ResultsSummary................................................................................................................................81
Methodology........................................................................................................................................82
KeyData Sources ................................................................................................................................82
Customer Segmentation Analysis........................................................................................................83
PotentialResults .................................................................................................................................85
B I Natural Gas Transportation Customer Conservation Potential...................................... 87
Background.........................................................................................................................................87
ResultsSummary................................................................................................................................87
Applied Energy Group, Inc.,proudly part of ICF 3 of 105
2025 Natural Gas IRP Appendix 93

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Methodology........................................................................................................................................88
KeyData Sources ................................................................................................................................89
PotentialResults .................................................................................................................................89
Considerations and Recommendations ..............................................................................................94
CMARKET PROFILES....................................................................................................... 95
D MARKET ADOPTION (RAMP) Rates ................................................................................ 97
EMeasure Data .............................................................................................................. 98
Applied Energy Group,Inc.,proudly part of ICF 4 of 105
2025 Natural Gas IRP Appendix 94

Avista Natural Gas Conservation Potential Assessment for 2026-2045
List of Figures
Figure 2-1 LoadMAP Analysis Framework......................................................................................................... 14
Figure 2-2 Approach for Conservation Measure Assessment........................................................................... 18
Figure 3-1 Avista Sector-Level Natural Gas Use(2021)..................................................................................... 27
Figure 3-2 Residential Natural Gas Use by Segment,Washington,2021 .......................................................... 28
Figure 3-3 Residential Natural Gas Use by End Use,Washington,2021 ........................................................... 29
Figure 3-4 Residential Energy Intensity by End Use and Segment,Washington,2021 ....................................... 30
Figure 3-5 Residential Natural Gas Use by Segment,Idaho,2021 .................................................................... 31
Figure 3-6 Residential Natural Gas Use by End Use, Idaho,2021 ..................................................................... 31
Figure 3-7 Residential Energy Intensity by End Use and Segment, Idaho,2021 (Annual Therms/HH)................ 32
Figure 3-8 Commercial Natural Gas Use by Segment,Washington,2021......................................................... 34
Figure 3-9 Commercial Sector Natural Gas Use by End Use,Washington,2021 .............................................. 34
Figure 3-10 Commercial Energy Usage Intensity by End Use and Segment,Washington,2021......................... 35
Figure 3-11 Commercial Natural Gas Use by Segment, Idaho,2021 ................................................................ 37
Figure 3-12 Commercial Sector Natural Gas Use by End Use, Idaho,2021 ...................................................... 37
Figure 3-13 Commercial Energy Usage Intensity by End Use and Segment, Idaho,2021 .................................. 38
Figure 3-14 Industrial Natural Gas Use by End Use,Washington,2021 ............................................................ 39
Figure 3-15 Industrial Natural Gas Use by End Use, Idaho,2021 ......................................................................40
Figure 4-1 Baseline Projection Summary by Sector,Washington ......................................................................43
Figure 4-2 Baseline Projection Summary by Sector, Idaho ...............................................................................44
Figure 4-3 Residential Baseline Projection by End Use,Washington ................................................................45
Figure 4-4 Residential Baseline Projection by End Use, Idaho..........................................................................46
Figure 4-5 Commercial Baseline Projection by End Use,Washington ..............................................................47
Figure 4-6 Commercial Baseline Projection by End Use, Idaho ........................................................................48
Figure 4-7 Industrial Baseline Projection by End Use,Washington...................................................................49
Figure 4-8 Industrial Baseline Projection by End Use, Idaho.............................................................................49
Figure 5-1 Cumulative Energy Efficiency Potential as%of Baseline Projection,Washington............................ 51
Figure 5-2 Baseline Projection and Energy Efficiency Forecasts,Washington .................................................. 51
Figure 5-3 Cumulative Energy Efficiency Potential as%of Baseline Projection, Idaho...................................... 52
Figure 5-4 Baseline Projection and Energy Efficiency Forecasts, Idaho ............................................................ 53
Figure 6-1 Cumulative Residential Potential as%of Baseline Projection,Washington..................................... 54
Figure 6-2 Residential TRC Achievable Economic Potential—Cumulative Savings by End Use,Washington..... 55
Figure 6-3 Cumulative Residential Potential as%of Baseline Projection, Idaho .............................................. 57
Figure 6-4 Residential UCT Achievable Economic Potential—Cumulative Savings by End Use, Idaho .............. 58
Figure 6-5 Cumulative Commercial Potential as%of Baseline Projection,Washington................................... 59
Figure 6-6 CommercialTRC Achievable Economic Potential—Cumulative Savings by End Use,Washington... 60
Figure 6-7 Cumulative Commercial Potential as%of Baseline Projection, Idaho............................................. 62
Figure 6-8 Commercial UCT Achievable Economic Potential—Cumulative Savings by End Use, Idaho ............ 63
Figure 6-9 Cumulative Industrial Potential as%of Baseline Projection,Washington ....................................... 65
Figure 6-10 Industrial TRC Achievable Economic Potential—Cumulative Savings by End Use,Washington ..... 66
Figure 6-11 Cumulative Industrial Potential as%of Baseline Projection,Idaho ............................................... 68
Figure 6-12 Industrial UCTAchievable Economic Potential—Cumulative Savings by End Use, Idaho............... 69
Figure 7-1 Demand Response Analysis Approach............................................................................................ 70
Figure 7-2 Coincident Peak Load Forecast by State(Winter)............................................................................ 73
Figure 7-3 Summary of Integrated Potential(Dtherms @ Generator)................................................................ 76
Figure 7-4 Summary of Potential by Option—(Dtherms @ Generator) .............................................................. 77
Figure 7-5 Potential by Sector—Dtherms @Generator,Washington.................................................................. 78
Figure 7-6 Potential by Sector—Dtherms @Generator, Idaho ........................................................................... 79
Figure 7-7 Potential by Sector—Dtherms @Generator, Oregon......................................................................... 79
Figure A- 1 Income Group Map84
Applied Energy Group, Inc.,proudly part of ICF 5 of 105
2025 Natural Gas IRP Appendix 95

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure B- 1 Reference Case Cumulative Potential,Washington...................................................................... 90
Figure B- 2 Reference Case Cumulative Potential,Oregon ............................................................................. 90
Applied Energy Group,Inc.,proudly part of ICF 6 of 105
2025 Natural Gas IRP Appendix 96

Avista Natural Gas Conservation Potential Assessment for 2026-2045
List of Tables
Table 1-1 Explanation of Abbreviations and Acronyms....................................................................................11
Table 2-1 Overview of Avista Analysis Segmentation Scheme.........................................................................15
Table 2-2 Number of Measures Evaluated.......................................................................................................19
Table 2-3 Data Applied for the Market Profiles ................................................................................................22
Table 2-4 Data Needs for Baseline Projection and Potentials Estimation in LoadMAP.....................................23
Table 2-5 Residential Natural Gas Equipment Standards..............................................................................A-1
Table 2-6 Commercial and Industrial Natural Gas Equipment Standards......................................................A-1
Table 2-7 Data Needs for Measure Characteristics in LoadMAP......................................................................25
Table 3-1 Residential Sector Control Totals,2021 ...........................................................................................27
Table 3-2 Residential Sector Control Totals,Washington,2021 ......................................................................28
Table 3-3 Average Market Profile for the Residential Sector,Washington,2021 ..............................................29
Table 3-4 Residential Sector Control Totals, Idaho,2021 ................................................................................30
Table 3-5 Average Market Profile for the Residential Sector, Idaho 2021 .........................................................32
Table 3-6 Commercial Sector Control Totals,Washington,2021 ....................................................................33
Table 3-7 Average Market Profile for the Commercial Sector,Washington,2021.............................................35
Table 3-8 Commercial Sector Control Totals, Idaho,2021 ..............................................................................36
Table 3-9 Average Market Profile for the Commercial Sector, Idaho,2021 ......................................................38
Table 3-10 Industrial Sector Control Totals, 2021 ...........................................................................................39
Table 3-11 Average Natural Gas Market Profile for the Industrial Sector,Washington,2021............................40
Table 3-12 Average Natural Gas Market Profile for the Industrial Sector, Idaho,2021 .....................................41
Table 4-1 Baseline Projection Summary by Sector,Washington(dtherms) ......................................................43
Table 4-2 Baseline Projection Summary by Sector, Idaho(dtherms) ...............................................................43
Table 4-3 Residential Baseline Projection by End Use,Washington (dtherms) ................................................45
Table 4-4 Residential Baseline Projection by End Use, Idaho(dtherms) ..........................................................46
Table 4-5 Commercial Baseline Projection by End Use,Washington(dtherms) ..............................................47
Table 4-6 Commercial Baseline Projection by End Use, Idaho(dtherms) ........................................................47
Table 4-7 Industrial Baseline Projection by End Use,Washington(dtherms)...................................................48
Table 4-8 Industrial Baseline Projection by End Use,Idaho(dtherms).............................................................49
Table 5-1 Summary of Energy Efficiency Potential,Washington......................................................................51
Table 5-2 Summary of Energy Efficiency Potential, Idaho................................................................................52
Table 6-1 Residential Energy Conservation Potential Summary,Washington..................................................54
Table 6-2 Residential Top Measures in 2026 and 2045,TRC Achievable Economic Potential,Washington......56
Table 6-3 Residential Energy Conservation Potential Summary, Idaho............................................................57
Table 6-4 Residential Top Measures in 2026 and 2045,TRC Achievable Economic Potential, Idaho................58
Table 6-5 Commercial Energy Conservation Potential Summary,Washington................................................59
Table 6-6 Commercial Top Measures in 2023 and 2035,TRC Achievable Economic Potential,Washington ....61
Table 6-7Commercial Energy Conservation Potential Summary, Idaho...........................................................62
Table 6-8 Commercial Top Measures in 2026 and 2045,TRC Achievable Economic Potential, Idaho..............64
Table 6-9 Industrial Energy Conservation Potential Summary,Washington.....................................................65
Table 6-10 Industrial Top Measures in 2026 and 2045,TRC Achievable Economic Potential,Washington.......67
Table 6-11 Industrial Energy Conservation Potential Summary, Idaho ............................................................68
Table 6-12 Industrial Top Measures in 2026 and 2045, UCT Achievable Economic Potential, Idaho ................69
Table7-1 Market Segmentation ......................................................................................................................71
Table 7-2 Baseline Customer Forecast by Customer Class,Washington ........................................................72
Table 7-3 Baseline Customer Forecast by Customer Class,Idaho..................................................................72
Table 7-4 Baseline Customer Forecast by Customer Class,Oregon ...............................................................72
Table 7-5 Baseline February Winter System Peak Forecast(Dth @Generation)by State..................................72
Table 7-6 DSM Steady-State Participation Rates(Percent of Eligible Customers)............................................74
Table 7-7 DSM Per Participant Impact Assumptions.......................................................................................75
Table 7-8 Summary of Integrated Potential(Dtherms @ Generator)................................................................76
Table 7-9 Summary of Potential by Option—(Dtherms @ Generator) ..............................................................77
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Table 7-10 Potential by Sector—Dtherms @Generator,Washington...............................................................78
Table 7-11 Potential by Sector—Dtherms @Generator, Idaho.........................................................................78
Table 7-12 Potential by Sector—Dtherms @Generator,Oregon ......................................................................78
Table 7-13 Levelized Program Costs and Potential..........................................................................................80
Table A- 1 Summary of Energy Efficiency Potential........................................................................................81
Table A- 2 Key Data Source Summary............................................................................................................83
Table A- 3 Customer Counts and Energy Consumption by Dwelling Type and Income Level,2021.................84
Table A- 4 Top Measures in 2026 and 2036,Achievable Economic Potential..................................................86
Table B- 1 Summary Potential Results—Reference Case,Washington.............................................................88
Table B-2 Summary Potential Results—Reference Case,Oregon...................................................................88
Table B-3 Key Data Source Summary.............................................................................................................89
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1 1 Introduction
In May 2023, Avista Corporation (Avista) engaged Applied Energy Group (AEG) to conduct a
Conservation Potential Assessment (CPA) for its Washington and Idaho service areas. AEG first
performed an electric CPA for Avista in 2013; since then,AEG has performed both electric and natural
gas CPAs for Avista's subsequent planning cycles. The CPA is a 20-year study of electric and natural
gas conservation potential, performed in accordance with Washington Initiative 937 and associated
Washington Administrative Code provisions. This study provides data on conservation resources to
support the development of Avista's 2025 Integrated Resource Plan (IRP). For reporting purposes, the
potential results are separated by fuel.This report documents the natural gas CPA.
Notable updates from prior CPAs include:
Forthe residential sector,the study still incorporates Avista's GenPOP residential saturation survey
from 2012, which provides a more localized look at Avista's customers than regional surveys. The
survey provided the foundation for the base year market characterization and energy market
profiles. The Northwest Energy Efficiency Alliance's (NEEA's) 2016 Residential Building Stock
Assessment II (RBSA) supplemented the GenPOP survey to account for trends in the intervening
years.
o Note that the 2022 RBSA was published in April 2024, too late in the study process to be
integrated into the baseline.
The list of energy conservation measures was updated with research from the Regional Technical
Forum(RTF). Connected Thermostats were removed from potential in all states due to the intention
of the RTF to sunset that measure at the end of 2025.
The study incorporates updated forecasting assumptions that align with the most recent Avista
Load forecast.
Updated information from the US Energy Information Administrations Residential and Commercial
Building Energy Consumption Surveys (RECS 2020 and CBECS 2018, both datasets released in
2022-2023) was used to supplement base year characterization of residential and commercial
customers
Enhancement retained from the previous CPA include:
- The residential segmentation differentiates low-income customers from others, with unique
market characterization, building shell and usage characteristics.
For the commercial sector, the analysis was performed for the major building types in the service
territory. Results from NEEA's 2019 Commercial Building Stock Assessment (CBSA), including
hospital and university data, provided useful information for this analysis. Measure
characterizations continue to use data from the Northwest Power and Conservation Council's 2021
Power Plan where this is the most current source, including measure data, adoption rates, and
updated measure applicability.
Summary of Report Contents
The report is divided into the following chapters, summarizingthe approach, assumptions, and results
of the electric CPA.
Chapter 2-Energy Efficiency Analysis Approach and Data Development. A detailed description
ofAEG's approach to estimatingthe energy efficiency potential and documentation of data sources
used.
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Chapter 3 — Energy Efficiency Market Characterization. Presents how Avista's customers use
natural gas today and what equipment is currently being used.
Chapter 4— Energy Efficiency Baseline Projection. Presents the baseline end-use projections
developed for each sector and state, as well as a summary.
Chapter 5 —Conservation Potential. Energy efficiency potential results for each state across all
sectors and separately for each sector.
Chapter 6—Sector-Level Energy Efficiency Potential. Summary of energy efficiency potential for
each market sector within Avista's service territory for both Washington and Idaho. This chapter
includes a detailed breakdown of potential by measure type, vintage, market segment, end use,
and state.
Chapter 7 — Demand Response Potential. Natural gas demand response potential results for
each state across all sectors and separately for each sector.
Volume 2,Appendices
The appendices for this report are provided in separate spreadsheets accompanying the delivery
of this report and consist of the following:
Oregon Low-Income Conservation Potential. Memo describing methodology and results of this
additional study.
Natural Gas Transportation Customer Conservation Potential. Memo describing methodology
and results of this additional study.
Market Profiles. Detailed market profiles for each market segment. Includes equipment
saturation, unit energy consumption or energy usage index, energy intensity, and total
consumption.
Market Adoption Rates. Documentation of the ramp rates used in this analysis. These were
adapted from the 2021 Power Plan electrical power conservation supply curve workbooks for the
estimation of achievable natural gas potential.
Measure Data. List of measures and input assumptions, along with baseline definitions and
efficiency options by market sector analyzed.
There are three types of tables presented in the report to easily distinguish between the types of data
presented. There is one type of table for each: general Avista data, Washington-specific data, and
Idaho-specific data.
Abbreviations and Acronyms
Error!Reference source not found. provides a list of abbreviations and acronyms used in this report,
along with an explanation.
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Table 1-1 Explanation ofAbbreviations and Acronyms
Acronym Explanation
ACS U.S.Census American Community Study
AEG Applied Energy Group
AEO EIA's Annual Energy Outlook
BEST AEG's Building Energy Simulation Tool
C&I Commercial and Industrial
CBSA NEEA's Commercial Building Stock Assessment
COMMEND EPRI's Commercial End-Use Planning System
CPA Conservation Potential Assessment
DEEM AEG's Database of Energy Efficiency Measures
DEER California Database for Energy Efficient Resources
DR Demand Response
DSM Demand Side Management
EIA Energy Information Administration
EPRI Electric Power Research Institute
EUI Energy Use Index
HDD Heating Degree Day
HVAC Heating Ventilation and Air Conditioning
IFSA NEEA's Industrial Facilities Site Assessment
IRP Integrated Resource Plan
Load MAP AEG's Load Management Analysis and Planning-tool
NEEA Northwest Energy Efficiency Alliance
NWPCC Northwest Power and Conservation Council
O&M Operations and Maintenance
RBSA NEEA's Residential Building Stock Assessment
REEPS EPRI's Residential End-Use Energy Planning System
RTF NWPCC's Regional Technical Forum
TRC Total Resource Cost test
TRM Technical Reference Manual
UCT Utility Cost Test
UEC Unit Energy Consumption
WSEC 2015 Washington State Energy Code
Acronym Explanation
ACS U.S.Census American Community Study
AEG Applied Energy Group
AEO ETA's Annual Energy Outlook
BEST AEG's Building Energy Simulation Tool
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2 1 Energy Efficiency Analysis Approach and Development
This section describes the analysis approach taken and the data sources used to develop the energy
efficiency potential estimates.The demand response analysis discussion can be found in 7 1
Overview of Analysis Approach
To perform the potential analysis, AEG used a bottom-up approach following the major steps listed
below.These steps are described in more detail throughout this section.
0. Perform a market characterization to describe sector-level electricity use for the residential,
commercial, and industrial sectors for the base year 2021. The market characterization
included extensive use of Avista data and other secondary data sources from NEEA and the
Energy Information Administration (EIA).
1. Develop a baseline projection of energy consumption and peak demand by sector, segment,
and end use for 2021 through 2045.
2. Define and characterize several hundred conservation measures to be applied to all sectors,
segments, and end uses.
3. Estimate technical, achievable technical, and achievable economic energy savings at the
measure level for 2026 through 2045. Achievable economic potential was assessed using the
Utility Cost Test(UCT)test for Avista's Idaho territory and the Total Resource Cost(TRC)test for
Avista's Washington territory. Comparison with NWPCC Methodology
It is important to note that electricity is the primary focus of the regionwide potential assessed in the
NWPCC's Plans. Natural gas impacts are typically assessed when they overlap with electricity
measures (e.g., gas water heating impacts in an electrically heated "Built Green Washington" home).
Although Avista is a dual-fuel utility,this study focuses on natural gas measures and programs,which
exhibit noticeable differences from electric programs, notably regarding avoided costs.To account for
this,AEG sometimes adapted NWPCC methodologies ratherthan usingthem directlyfrom the source.
This adaptation is especially relevant in the development of ramp rates when achievability was
determined not to be applicable to a specific natural gas measure or program.
A primary objective of the study was to estimate natural gas potential consistent with the NWPCC's
analytical methodologies and procedures for electric utilities. While developing Avista's 2025 - 2045
CPA, AEG relied on an approach vetted and adapted through the successful completion of CPAs
referencing the NWPCC's Fifth,Sixth,Seventh, and now 2021 Power Plans.Among other aspects,this
approach involves using consistent:
Data sources:Avista surveys, regional surveys, market research, and assumptions
Measures and assumptions:Avista TRM, 2021 Power Plan supply curves and RTF work products
Potential factors: 2021 Power Plan ramp rates
Levels of potential:technical, achievable technical, and achievable economic
Cost-effectiveness approaches: assessed potential under the UCT for Idaho and TRC for
Washington, including non-energy impacts(and non-gas energy impacts),which may be quantified
and monetized, as well as operations and maintenance (O&M) impacts within the TRC.
Conservation credit: applied NWPCC 10% conservation credit to avoided energy costs in
Washington for energy benefits.This is incorporated into the TRC calculation.
AEG used its Load Management Analysis and Planning tool(Load MAP'")version 5.0 to develop both the
baseline projection and the estimates of potential. AEG developed Load MAP in 2007 and has
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enhanced it overtime, using it for the Electric Power Research Institute(EPRI) National Potential Study
and numerous utility-specific forecasting and potential studies since that time. Built in Excel, the
Load MAP framework (see Figure 2-1) is both accessible and transparent and has the following key
features:
Embodies the basic principles of rigorous end-use models(such as EPRI's REEPS and COMMEND)
but in a more simplified, accessible form.
Includes stock-accounting algorithms that treat older, less efficient appliance/equipment stock
separatelyfrom newer, more efficient equipment. Equipment is replaced accordingto the measure
life and appliance vintage distributions defined by the user.
Balances the competing needs of simplicity and robustness. This is done by incorporating
important modeling details related to equipment saturations, efficiencies, vintage, and the like,
where market data are available, and treats end uses separately to account forvarying importance
and availability of data resources.
Isolates new construction from existing equipment and buildings and treats purchase decisions
for new construction and existing buildings separately. This is especially relevant in the state of
Washington where the 2015 Washington State Energy Code (WSEC) substantially enhances the
efficiency of the new construction market.
Uses a simple logic for appliance and equipment decisions. Other models available for this
purpose embody complex decision-choice algorithms or diffusion assumptions. The model
parameters tend to be difficult to estimate or observe, and sometimes produce anomalous results
that require calibration or even overriding. The LoadMAP approach allows the user to drive the
appliance and equipment choices year by year directly in the model.This flexible approach allows
users to import the results from diffusion models or to input individual assumptions. The
framework also facilitates sensitivity analysis.
Includes appliance and equipment models customized by end use. For example,the logic forwater
heating is distinct from furnaces and fireplaces.
Can accommodate various levels of segmentation. Analysis can be performed at the sector level
(e.g., total residential) or for customized segments within sectors (e.g., housing type, state, or
income level).
Natively outputs model results in a detailed line-by-line summary file, allowing for review of input
assumptions, cost-effectiveness results, and potential estimates at a granular level. Also allows
for the development of IRP supply curves, both at the achievable technical and achievable
economic potential levels.
Can incorporate conservation measures, demand-response options, combined heat and power,
distributed generation options, and fuel switching.
Consistent with the segmentation scheme and market profiles described below, Load MAP provides
projections of baseline energy use by sector, segment, end use, and technology for existing and new
buildings. It provides forecasts of total energy use and energy efficiency savings associated with the
various types of potential.
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Figure 2-1 LoadMAPAnaiysis Framework
Base-year Energy Forecast Energy Efficiency
Market Profiles — Consumption Assumptions Analysis Forecast Results
• Market size and Bytechnology, • Customer, • List of measures • Baseline end use
segmentation end use, growth,energy • Saturations and projection
• Equipment segment,vintage prices, applicabilities Energy efficiency
saturation sector,and state elasticities . Measure costs projections \
• Vintage • Efficiency . Lifetime • Technical /
distribution options,codes . Adoption rates • Achievable
• Unit energy and standards, Techical
purchase shares • Avoided costs
consumption • Cost- • Achievable
• Existing and new effectiveness Economic
construction — — (UCT and TRC)
Definitions of Potential
AEG's approach for this study adheres to the approaches and conventions outlined in the National
Action Plan for Energy Efficiency's Guide for Conducting Potential Studies and is consistent with the
methodology used by the Northwest Power and Conservation Council to develop its regional power
plans. The guide represents the most credible and comprehensive industry practice for specifying
conservation potential.Two types of potential were developed as part of this effort:
Technical Potential is the theoretical upper limit of conservation potential. It assumes that
customers adopt all feasible efficient measures regardless of their cost. At the time of existing
equipment failure, customers replace their equipment with the most efficient option available. In
new construction, customers and developers choose the efficient equipment option relative to
applicable codes and standards. Non-equipment measures, which may be realistically installed
apart from equipment replacements, are implemented according to ramp rates developed by the
NWPCC for its 2021 Power Plan, applied to 100% of the applicable market. This case is provided
primarily for planning and informational purposes.
Achievable Technical Potential refines Technical Potential by applying market adoption rates that
account for market barriers, customer awareness and attitudes, program maturity, and other
factors that may affect market penetration of energy efficiency measures. AEG used achievability
assumptions from the NWPCC's 2021 Power Plan, adjusted for Avista's recent program
accomplishments, as the customer adoption rates for this study. For the achievable technical
case, ramp rates are applied to between 85% - 100% of the applicable market, per NWPCC
methodology. This achievability factor represents potential that all available mechanisms,
including utility programs, updated codes and standards, and market transformation, can
reasonably acquire. Thus, the market applicability assumptions utilized in this study include
savings outside of utility programs.The market adoption factors can be found in Appendix D.
UCT Achievable Economic Potential further refines achievable technical potential by applying a
cost-effectiveness screen.The UCT test assesses cost-effectiveness from the utility's perspective.
This test compares lifetime energy benefits to the costs of delivering the measure through a utility
program, excluding monetized non-energy impacts.The costs are the incentive, as a percent of the
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incremental cost of the given measure, relative to the relevant baseline (e.g.,the federal standard
for lost opportunity and no action for retrofits), plus any administrative costs that are incurred by
the program to deliver and implement the measure. If the benefits outweigh the costs(that is, if the
UCT ratio is greater than 1.0), a given measure is included in the economic potential.
TRC Achievable Economic Potential also refines achievable technical potential through cost-
effectiveness analysis. The TRC test assesses cost-effectiveness from a combined utility and
participant perspective. As such, this test includes the full cost of the measure and non-energy
impacts realized by the customer(if quantifiable and monetized). AEG also assessed the impacts
of non-gas savingsfollowingthe NWPCC methodology. Forthe assessment,AEG used a calibration
credit for space heating equipment consumption to account for secondary heating equipment
present in an average home as well as other electric end-use impacts, such as cooling and interior
lighting(as applicable), on a measure-by-measure basis.
Market Characterization
To estimate the savings potential from energy efficient measures, it is necessary to understand how
much energy is used today and what equipment is currently being used. The characterization begins
with a segmentation of Avista's electricity footprint to quantify energy use by sector,segment,end-use
application,and the current set of technologies used.To complete this step,AEG relied on information
from Avista, NEEA, and secondary sources, as necessary.
Segmentation for Modeling Purposes
The market assessment first defined the market segments (building types, end uses, and other
dimensions)that are relevant in the Avista service territory.The segmentation scheme for this project
is presented in Table 2-1.
Table 2-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description
1 Sector Residential,commercial, industrial
Residential:single family, multifamily, manufactured home,
differentiated by income level
2 Segment Commercial:small office, large office,restaurant,retail,grocery,
college,school, health, lodging,warehouse,and miscellaneous
Industrial:total
3 Vintage Existing and new construction
4 End uses Heating,secondary heating,water heating,food preparation,
process,and miscellaneous(as appropriate by sector)
5 Appliances/end uses and Technologies such as furnaces,water heaters,and process heating
technologies by application,etc.
6 Equipment efficiency levels for Baseline and higher-efficiency options as appropriate for each
new purchases technology
With the segmentation scheme defined, AEG then performed a high-level market characterization of
natural gas sales in the base year to allocate sales to each customer segment. AEG used Avista data
and secondary sources to allocate energy use and customers to the various sectors and segments
such that the total customer count, and energy consumption matched the Avista system totals from
billing data.This information provided control totals at a sector levelfor calibrating LoadMAP to known
data for the base year.
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Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and
technology.The market profiles provide the foundation for the development of the baseline projection
and the potential estimates.A market profile includes the following elements:
Market size is a representation of the number of customers in the segment. For the residential
sector, it is the number of households. In the commercial sector, it is floor space measured in
square feet. For the industrial sector, it is the number of employees.
Saturations define the fraction of homes or square feet with the various technologies(e.g., homes
with electric space heating).
o Conditioned space accounts for the fraction of each building that is conditioned by the end
use, applyingto cooling and heating end uses.
o The whole-building approach measures shares of space in a building with an end use
regardless of the portion of each building served by the end use. Examples are commercial
refrigeration,food service, and domestic water heating and appliances.
o The 100%saturation approach applies to end uses generally present in every building or home
and are set to 100% in the base year.
UEC (unit energy consumption) or EUI (energy use index) describes the amount of energy
consumed in 2021 by a specific technology in buildings that have the technology. UECs are
expressed in therms/household forthe residential sector,and EUIs are expressed in therms/square
foot for the commercial sector, or therms/employee for the industrial sector.
Annual Energy Intensity for the residential sector represents the average energy use for the
technology across all homes in 2021 and is the product of the saturation and UEC.The commercial
and industrial sectors represent the average use for the technology across all floor space or
employees in 2021 and is the product of the saturation and EUI.
Annual Usage is the annual energy use by an end-use technology in the segment. It is the product
of the market size and intensity and is quantified in therms or dtherms.
The market characterization is presented in Chapter 3, and market profiles are presented in Appendix
C.
Baseline Projection
The next step was to develop the baseline projection of annual natural gas use for 2021 through 2045
by customer segment and end use in the absence of new utility energy efficiency programs. The
savings from past programs are embedded in the forecast, but the baseline projection assumes that
those past programs cease to exist in the future. Possible savings from future programs are captured
bythe potential estimates.The projection includes the impacts of known codes and standards,which
will unfold over the study timeframe. All such mandates that were defined as of January 2024 are
included in the baseline.
The baseline projection is the foundation for the analysis of savings from future conservation efforts
as well as the metric against which potential savings are measured. Although AEG's baseline
projection aligns closely with Avista's, it is not Avista's official load forecast.
Inputs to the baseline projection include:
Avista's official forecast(Heating Degree Days base 65°F(HDD65)), calibrated to actual sales
Current economic growth forecasts (i.e., customer growth, income growth, changes in weather
(HDD65 normalization)))
Natural gas price forecasts
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Trends in fuel shares and equipment saturations
Existing and approved changes to building codes and equipment standards
Avista's internally developed sector-level projections for natural gas sales
The baseline projection is presented in Chapter 4.
Conservation Measure Analysis
This section describes the framework used to assess conservation measures' savings, costs, and
other attributes. These characteristics form the basis for measure-level cost-effectiveness analyses
and for determining measure savings. For all measures, AEG assembled information to reflect
equipment performance, incremental costs, and equipment lifetimes. We used this information
combined with Avista's avoided cost data to inform the economic screens that Leadetermine
economicallyfeasible measures.
Conservation Measures
Error! Reference source not found. outlines the framework for conservation measure analysis. The
framework involves identifying the list of measures to include in the analysis, determining their
applicability to each sector and segment, fully characterizing each measure. Potential measures
include the replacement of a unit that has failed or is at the end of its useful life with an efficient unit,
retrofit,or early replacement of equipment, improvements to the building envelope,the application of
controls to optimize energy use, and other actions resulting in improved energy efficiency.
AEG compiled a robust list of conservation measures for each customer sector, drawing upon Avista's
measure database,the RTF, and the 2021 Power Plan deemed measures database, as well as a variety
of secondary sources. This universal list of conservation measures covers all major types of end-use
equipment, as well as devices and actions to reduce energy consumption. Avista provided feedback
during each step to ensure measure assumptions and results lined up with programmatic experience.
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Figure 2-2 Approach for Conservation Measure Assessment
Inputs Process
Avista Review/Feedback
Avista Measure Data
(TRMs,Program Data, ` - • •
Evaluated Savings,etc.)
Energy Savings
•
AEG Measure Data Library
Costs and NEIs
Lifetime
Building Simulations Applicability Saturation&
The selected measures are categorized into the two following types according to the LoadMAP
taxonomy:
Equipment measures are efficient energy-consuming pieces of equipment that save energy by
providingthe same service with a lower energy requirement than a standard unit. An example is an
ENERGY STAR°residential water heater(UEF 0.64)that replaces a standard efficiencywater heater
(UEF 0.58). For equipment measures, many efficiency levels may be available for a given
technology, ranging from the baseline unit(often determined by code or standard) up to the most
efficient product commercially available. These measures are applied on a stock-turnover basis
and are generally referred to as lost opportunity measures by the NWPCC because once a
purchase decision is made, there will not be another opportunity to improve the efficiency of the
equipment until its effective useful life is reached.The 2021 Power Plan's"Lost Opportunity"ramp
rates are primarily applied to equipment measures.
Non-equipment measures save energy by reducing the need for delivered energy but do not
involve replacement or purchase of major end-use equipment(such as a furnace or water heater).
An example would be a programmable thermostat that is pre-set to run heating systems onlywhen
people are home. Non-equipment measures can apply to more than one end use or fuel type. For
instance, the addition of wall insulation will affect the energy use of both space heating and
cooling. The 2021 Power Plan's "Retrofit" ramp rates are primarily applied to non-equipment
measures. Non-equipment measures typically fall into one of the following categories:
o Building shell(windows, insulation, roofing material)
o Equipment controls(thermostat, water heater setback)
o Equipment maintenance(cleaning filters, changing setpoints)
o Whole-building design (building orientation, advanced new construction designs)
o Commissioning and Retrocommissioning (initial or ongoing monitoring of building energy
systems to optimize energy use)
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We developed a preliminary list of conservation measures,which was distributed to the Avista project
team for review. The list was finalized after incorporating comments. Next, the project team
characterized measure savings, incremental cost, service life, non-energy impacts, and other
performance factors, drawing upon data from the Avista measure database, the 2021 Power Plan,the
RTF deemed measure workbooks, simulation modeling, and other well-vetted sources as required.
Following the measure characterization, we performed an economic screening of each measure,
which serves as the basis for developing the economic and achievable potential scenarios. Measure
data can be found in Appendix C. Table 2-2 summarizes the number of measures evaluated for each
segment within each sector.
Table 2-2 Number of Measures Evaluated
Sector Total Measure Permutations Measure Permutationsw/
Measures w/2 Vintages All Segments&States
Residential 64 128 1,536
Commercial 76 152 3,040
Industrial 43 86 172
Total Measures Evaluated 183 366 4,748
Data Development
This section details the data sources used in this study,followed by a discussion of how these sources
were applied. In general, data sources were applied in the following order: Avista data, Northwest
regional data, and well-vetted national or other regional secondary sources. Data were adapted to
local conditions, for example, by using local sources for measure data and local weather for building
simulations.
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
Customer Data:Avista provided billing data for the development of customer counts and energy
use for each sector.We also used the results of the Avista GenPOP survey, a residential saturation
su rvey.
Load Forecasts:Avista provided forecasts, by sector and state, of energy consumption, customer
counts,weather actuals for 2021, as well as weather-normal HDD65.
Economic Information: Avista provided a discount rate as well as avoided cost forecasts
consistent with those utilized in the IRP.
Program Data:Avista provided information about past and current programs, including program
descriptions, goals, and achievements to date.
Avista TRM:Avista provided energy conservation measure assumptions within current programs.
We utilized this as a primary source of measure information, supplemented secondary data.
Northwest Energy Efficiency Alliance Data
The NEEA conducts research for the Northwest region. The NEEA surveys were used extensively to
develop base saturation and applicability assumptions for many of the non-equipment measures
within the study. The following studies were particularly useful:
RBSA II, Single-Family Homes Report 2016-2017.
RBSA II, Manufactured Homes Report 2016-2017.
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• RBSA II, Multifamily Buildings Report 2016-2017.
• 2019 Commercial Building Stock Assessment(CBSA), May 21,2020.
• 2014 Industrial Facilities Site Assessment(IFSA), December 29,2014.
Northwest Power and Conservation Council Data
Several sources of data were used to characterize the conservation measures.We used the following
regional data sources and supplemented them with AEG's data sources to fill in any gaps.
RTF Deemed Measures.The NWPCC RTF maintains databases of deemed measure savings data.
NWPCC 2021 Power Plan Conservation Supply Curve Workbooks.To develop its 2021 Power Plan,
the Council used workbooks with detailed information about measures.
• NWPCC, MC and Loadshape File, September 29, 2016. The Council's load shape library was
utilized to convert CPA results into hourly conservation impacts for use in Avista's IRP process.
AEG Data
AEG maintains several databases and modeling tools that we use for forecasting and potential studies.
Relevant data from these tools have been incorporated into the analysis and deliverables for this
study.
AEG Energy Market Profiles: AEG maintains regional profiles of end-use consumption. The
profiles include market size, fuel shares, unit consumption estimates, annual energy use by fuel
(electricity and natural gas), customer segment, and end use for ten (10) regions in the U.S. The
U.S. Energy Information Administration (EIA) surveys (RECS, CBECS, and MECS), as well as state-
level statistics and local customer research provide the foundation for these regional profiles.
Building Energy Simulation Tool (BEST): AEG's BEST is a derivative of the DOE 2.2 building
simulation model, used to estimate base-year UECs and EUIs, as well as measure savings for the
HVAC-related measures.
AEG's Database of Energy Efficiency Measures(DEEM):AEG maintains an extensive database
of measure data, drawing upon reliable sources including the California Database for Energy
Efficient Resources (DEER), the EIA Technology Forecast Updates — Residential and Commercial
Building Technologies—Reference Case, RS Means cost data, and Grainger Catalog Cost data.
Recent studies: AEG has conducted numerous studies of energy efficiency potential in the last
five years, both within the region and across the country. We checked our input assumptions and
analysis results against the results from these other studies both within the region and across the
country.
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main sources
include:
Annual Energy Outlook (AEO): Conducted each year by the U.S. EIA, the AEO presents yearly
projections and analysis of energy topics. For this study,we used data from the 2023 AEO.
EIA Survey Data (RECS, CBECS, MECS): Used to supplement end use saturations and
consumption where more local data was not available. This study used data from the 2020 RECS,
2018 CBECS, and 2018 MECS,which are the most recent data sets available.
Local Weather Data:Weather from National Oceanic and Atmospheric Administration's National
Climatic Data Center for Spokane,Washington and Coure d'Alene in Idaho were used as the basis
for building simulations.
Other relevant regional sources: These include reports from the Consortium for Energy
Efficiency,the Environmental Protection Agency, and the American Council for an Energy-Efficient
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Economy. When using data from outside the region, especially weather-sensitive data, AEG
adapted assumptions for use within Avista's territory.
Data Application
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of natural gas consumption and market size units
(households for residential, floor space for commercial, and employees for industrial), we primarily
used Avista's billing data as well as secondary data from AEG's Energy Market Profiles database.
Residential Segments.To distinguish low-income households within each housing segment,AEG
cross referenced geographic data from Avista's customer database with data from the US Census
American Community Survey to estimate the presence of low-income households within Avista's
service territory."Low Income"was defined by household size. In Washington the threshold is 80%
of Area Median Income, and in Idaho it is 200% of the Federal Poverty Level. Data from NEEA's
Residential Building Stock Assessment (RBSA II, 2016) was used to differentiate energy
characteristics of low-income households, including differences in building shells, energy use per
customer, and presence of energy-using equipment.
C&I Segments. Customers and sales were allocated to building type based on intensity and floor
space data from the 2019 Commercial Building Stock Assessment (CBSA) by state, with some
adjustments between the C&I sectors to better group energy use by facility type and predominate
end uses.
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are shown in
Table 2-3.To develop the market profiles for each segment, AEG performed the following steps:
1. Developed control totals for each segment. These include market size, segment-level annual
natural gas use, and annual intensity. Control totals were based on Avista's actual sales and
customer-level information found in Avista's customer billing database.
4. Developed existing appliance saturations and the energy characteristics of appliances,
equipment, and buildings using equipment flags within Avista's billing data; NEEA's RBSA,
CBSA, and IFSA; U.S. ETA's surveys and AEO; and the American Community Survey.
5. Ensured calibration to control totals for annual natural gas sales in each sector and segment.
6. Compared and cross-checked with other recent AEG studies.
7. Worked with Avista staff to vet the data against their knowledge and experience.
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Table 2-3 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Avista billing data
Base-year residential dwellings, Avista GenPOP Survey
Market size commercial floor space,and industrial
NEEA RBSA and CBSA
employment
AEO 2023
Avista billing data
Residential:Annual use per household US DOE RECS and CBECS data
Annual intensity Commercial:Annual use per square foot NEEA RBSA and CBSA
Industrial: Annual use per employee AEO 2023
Other recent studies
Fraction of dwellings with an Avista GenPOP Survey
Appliance/equipment appliance/technology NEEA RBSA,CBSA,and IFSA
saturations Percentage of C&I floor space/employment ACS
with equipment/technology AEG's Energy Market Profiles
HVAC uses: BEST simulations using prototypes
UEC:Annual natural gas use in homes and developed for Avista
UEC/EUI for each end- buildings that have the technology Engineering analysis
use technology EUI:Annual natural gas use per square RTF workbooks if applicable
foot/employee for a technology in floor
space that has the technology AEO 2023
Recent AEG studies
Appliance/equipment Age distribution for each technology RBSA,CBSA,and recent AEG studies
age distribution
Avista current program offerings
Efficiency options for List of available efficiency options and AEO 2023
each technology annual energy use for each technology RTF and NWPCC 2021 Plan data
Data Application for Baseline Projection
Table 2-4 summarizes the Load MAP model inputs required for the baseline projection. These inputs
are required for each segment within each sector, as well as for new construction and existing
dwellings/buildings.
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Table 2-4 Data Needs for Baseline Projection and Potentials Estimation in LoadMAP
Model.Inputs Description
Customer growth Forecasts of new construction in Avista load forecast
forecasts residential,commercial,and industrial AEO 2023 economic growth forecast
sectors
Equipment For each equipment/technology, purchase Shipments data from AEO and ENERGY STAR
purchase shares shares for each efficiency level;specified AEO 2023 regional forecast assumptions'
for baseline separately for existing equipment Appliance/efficiency standards analysis
projection replacement and new construction Avista program results and evaluation reports
EPRI's REEPS and COMMEND models
Utilization model Price elasticities,elasticities for other
p Avista short-term forecast calibration
parameters variables(income,weather)
AEO 2023
' We developed baseline purchase decisions using the EIA's AEO report,which utilizes the National Energy Modeling System to produce a self-
consistent supply and demand economic model.We calibrated equipment purchase options to match distributions/allocations of efficiency levels
to manufacturer shipment data for recentyears.
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Table 2-5 Residential Natural Gas Equipment Standards
Technology 20211 1 /
Space Heating Furnace—Direct Fuel AFUE 80% AFUE 90%
Boiler—Direct Fuel AFUE 80%
Secondary Fireplace N/A
Heating
Water Heater<=55 gal. UEF 0.58
Water Heating
Water Heater>55 gal. UEF 0.76
Clothes Dryer CEF 3.30
Appliances
Stove/Oven N/A
Pool Heater TE 0.82
Miscellaneous
Miscellaneous N/A
Table 2-6 Commercial and Industrial Natural Gas Equipment Standards
End-Use Technology 2021 2022
Furnace AFUE 80%/TE 0.80 TE 0.90
Space Heating Boiler Average around AFUE 80%/TE 0.80(varies by size)
Unit Heater Standard(intermittent ignition and powerventing or automatic flue damper)
Water Heater Water Heating TE 0.80
Food Fryer N/A ENERGY STAR3.0
Preparation Steamer N/A ENERGY STAR 1.2
Miscellaneous Pool Heater TE 0.82
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Conservation Measure Data Application
Table 2-7 details the energy efficiency data inputs to the Load MAP model, describes each input, and
identifies the key sources used in the analysis.
Table 2-7 Data Needs for Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Avista measure data
NWPCC 2021 Plan
The annual reduction in consumption attributable to each conservation workbooks
Energy Impacts specific measure.Savings were developed as a percentage RTF workbooks
of the energy end use that the measure affects.
AEG BEST
Other secondary sources
Equipment Measures: Includes the full cost of purchasing
and installing the equipment on a per-household, per-
square-foot, per employee or per service point basis for the Avista measure data
residential,commercial,and industrial sectors,respectively. NWPCC 2021 Plan
Costs Non-equipment measures: Existing buildings—full installed conservation workbooks, RTF
cost. New Construction -the costs may be either the full AEO 2023
cost of the measure,or as appropriate,the incremental cost Other secondary sources
of upgrading from a standard level to a higher efficiency
Level.
Avista measure data
NWPCC 2021 Plan
Estimates derived from the technical data and secondary conservation workbooks , RTF
Measure data sources that support the measure demand and energy AEO 2023
Lifetimes savings analysis. AEG DEEM
DEER
Other secondary sources
RBSA,CBSA
WSEC for limitations on new
Estimate of the percentage of dwellings in the residential construction
Applicability sector,square feet in the commercial sector,or employees NWPCC 2021 Plan
in the industrial sector where the measure is applicable and
conservation workbooks
where it is technically feasible to implement.
RTF workbooks
Other secondary sources
On Market and Expressed as years for equipment measures to reflect when AEG appliance standards and
Off Market the equipment technology is available or no longer available building codes analysis
Availability in the market.
Data Application for Cost-effectiveness Screening
All cost and benefit values were analyzed as real dollars,converted from nominal provided byAvista.
We applied Avista's long-term discount rate of 4.29%excluding inflation. Load MAP is configured to
vary this by market sector (e.g., residential and commercial) if Avista develops alternative values in
the future.
Estimates of Customer Adoption
• Two parameters are needed to estimate the timing and rate of customer adoption in the potential
forecasts.Technical diffusion curves for non-equipment measures. Equipment measures are
installed when existing units fail. Non-equipment measures do not have this natural periodicity,
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so rather than installing all available non-equipment measures in the first year of the projection
(instantaneous potential), they are phased in according to adoption schedules that generally
align with the diffusion of similar equipment measures. Like the 2022 CPA, we applied the
"Retrofit" ramp rates from the 2021 Power Plan directly as diffusion curves. For technical
potential,these rates summed up to 100%by the 20th year for all measures.
Adoption rates. Customer adoption rates or take rates are applied to technical potential to
estimate Technical Achievable Potential. For equipment measures, the Council's "Lost
Opportunity" ramp rates were applied to technical potential with a maximum achievability of
85%-100%, depending on the measure. For non-equipment measures, the Council's "Retrofit"
ramp rates have already been applied to calculate technical diffusion. In this case, we multiply
each of these by 85%(for most measures)to calculate Achievable Technical Potential.Adoption
rates are presented in Appendix D.
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3 1 Energy Efficiency Market Characterization
This chapter presents how Avista's customers in Washington and Idaho use natural gas in 2021,the
base year of the study. We begin with a high-level summary of energy use by state and then delve
into each sector.
Energy Use Summary
Avista's total natural gas consumption for the residential,commercial,and industrial sectors in 2021
was 27,285,801 dtherms (dtherms or dth); 18,288,700 dtherms in Washington and 8,997,101
dtherms in Idaho.As shown in Table 3-1 and ,the residential sector accounts for the largest share of
annual energy use at 62%,followed by the commercial sector at approximately 35%.
Table 3-1 Residential Sector Control Totals,2021
Washington ldaho�
Sector Natural Gas %of Annual Use Natural Gas Usage %of Annual Use
Residential 11,356,811 62.1% 5,617,143 62.4%
Commercial 6,665,122 36.4% 3,149,752 35.0%
Industrial 266,766 1.5% 230,206 2.6%
Total 18,288,700 100% 8,997,101 100%
Figure 3-1 Avista Sector-Level Natural Gas Use(2021)
Washington Idaho
Industrial
Industrial 3%
2%
mercial
-
00
70 A4
000 00,
0 00'�"' 'A 0'
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Residential Sector
Washington Characterization
The total number of households and natural gas sales for the service territory were obtained from
Avista's actual sales. In 2021, there were 157,808 households in the state of Washington that used
a total of 11,356,811 dtherms, resulting in an average use per household of 720 therms per year.
Table 3-2 and Figure 3-2 shows the total number of households and natural gas sales in the six
residential segments for each state. These values represent weather actuals for 2021 and were
adjusted within LoadMAP to normal weather using heating degree day, base 65°F, using data
provided byAvista.
Table 3-2 Residential Sector Control Totals, Washington,2021
Segment Households Natural Gas Use Annual Use/Customer
Single Family 84,836 7,324,885 863
Multi-Family 8,705 431,675 496
Mobile Home 5,136 305,566 595
Low Income-Single Family 39,810 2,481,707 623
Low Income—Multi-Family 15,263 546,435 358
Low Income—Mobile Home 4,057 266,544 657
Total 157,808 11,356,811 720
Figure 3-2 Residential Natural Gas Use by Segment, Washington,2021
LI-Multi-Family LI-Mobile Home
5% 2%
LI-Single Family
22% Single FamiLy
Mobile Home -
3
e"��
Multi-Family
4%
Figure 3-3 and Table 3-3 show the distribution of annual natural gas consumption by end use for an
average residential household.Space heating comprises most of the load at 83%,followed bywater
heating at 12%. Appliances, secondary heating, and miscellaneous loads make up the remaining
portion (5%) of the total load.
The market profiles provide the foundation for development of the baseline projection and the
potential estimates.The average market profile for the residential sector is presented in Table 3-3.
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Figure 3-3 Residential Natural Gas Use by End Use, Washington,2021
Appliances� Miscellaneous
3/0 0%
Secondary Water
Heating Heating
2% 12%
Space
Table 3-3 Average Market Profile for the Residential Sector, Washington,2021
End Use Technotogy Saturation UEC Intensity Usage
Furnace-Direct Fuel 84.8% 685 581 9,175,585
Space Heating
Boiler-Direct Fuel 2.4% 628 15 233,076
Secondary Heating Fireplace 5.1% 216 11 172,769
Water Heater(—55 Gal) 55.1% 156 86 1,356,503
Water Heating
Water Heater(>55 Gal) 0.0% 148 0 457
Clothes Dryer 28.4% 23 6 101,141
Appliances
Stove/Oven 58.6% 31 18 286,622
Pool Heater 0.9% 106 1 15,120
Miscellaneous
Miscellaneous 100% 1 1 15,539
Total 720 11,356,811
Figure 3-4 presents average natural gas intensities by end use and housingtype.Single family homes
consume substantially more energy in space heating because single family homes are larger and
more walls are exposed to the outside environment, compared to multifamily dwellings with many
shared walls. Additional exposed walls increase heat transfer, resulting in greater heating loads.
Water heating consumption is also higher in single family homes due to a greater number of
occupants.
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Figure 3-4 Residential Energy Intensity by End Use and Segment, Washington,2021
1,000
900
800 ■Space Heating
700
Secondary Heating
= 600
E 500 [ Water Heating
L
400 Appliances
300 ■Miscellaneous
200
100
0
Single Family Multi-Family Mobile Home LI-Single LI-Multi- LI-Mobile Average
Family Family Home Home
Idaho Characterization
In 2021, there were 80,127 households in Avista's Idaho territory that used a total of 5,617,143
dtherms, resulting in an average use per household of 701 therms per year. Table 3-4 and Figure 3-5
shows the total number of households and natural gas sales in the six residential segments for each
state.
Table 3-4 Residential Sector Control Totals,Idaho,2021
Segment Households Naturat Gas Use Annual Use/Customer
Single Family 55,954 4,471,261 799
Multi-Family 8,690 379,050 436
Mobile Home 5,585 261,344 468
Low Income—Single Family 6,505 377,733 581
Low Income—Multi-Family 2,685 85,112 317
Low Income—Mobile Home 708 42,642 603
Total 80,127 5,617,143 701
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Figure 3-5 Residential Natural Gas Use by Segment,Idaho,2021
LI-Multi-Family
LI-SingLe 1% LI-Mobile Home
Family 1%
7% IMobile Home
5%
Multi-Family
7%
Single Family
Figure 3-6 and
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Table 3-5 show the distribution of annual natural gas consumption by end use for an average
residential household. Space heating comprises most of the load at 84%,followed by water heating
at 12%. Appliances, secondary heating, and miscellaneous loads make up the remaining portion
(4%) of the total load.
Figure 3-6 Residential Natural Gas Use by End Use, Idaho,2021
Appliances Miscellaneous
2% 1r
I 0%
Secondary Water
Heating Heating
2% 12%
Space
:,.
—.00A
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Table 3-5 Average Market Profile for the Residential Sector, Idaho 2021
End Use Technology Saturation UEC Intensity Usage
Furnace-Direct Fuel 88.0% 669 589 4,715,719
Space Heating
Boiler-Direct Fuel 0.0% - - -
Secondary Heating Fireplace 6.0% 225 14 108,339
Water Heater(< 55 Gal) 50.9% 152 77 618,978
Water Heating
Water Heater(>55 Gal) 4.3% 151 7 52,229
Clothes Dryer 16.2% 22 4 28,672
Appliances
Stove/Oven 34.7% 30 11 84,402
Pool Heater 0.3% 106 0 2,848
Miscellaneous —
Miscellaneous 100% 1 1 5,958
Total 701 5,617,143
Figure 3-7 presents average natural gas intensities by end use and housingtype.Single family homes
consume substantially more energy in space heating.Water heating consumption is higher in single
family homes as well, due to a greater number of occupants, which increases the demand for hot
water.
Figure 3-7Residential Energy Intensity by End Use and Segment, Idaho,2021 (Annual Therms/HH)
900
800
700 ■Space Heating
600 Secondary Heating
500 —
Water Heating
a`) 400
Appliances
300
■Miscellaneous
200
100 r -
0
Single Family Multi-Family Mobile Home LI-Single LI-Multi- LI-Mobile Average
Family Family Home Home
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Commercial Sector
Washington Characterization
The total natural gas consumed by commercial customers in Avista's Washington service area in
2021 was 6,665,122 dtherm.The total number of non-residential accounts and natural gas sales for
the Washington service territory were obtained from Avista's customer account database. AEG
separated the commercial and industrial accounts by analyzing the SIC codes and rate codes
assigned in the billing system. Energy use from accounts where the customer type could not be
identified were distributed proportionally to all C&I segments. Once the billing data was analyzed,
the final segment control totals were derived by distributing the total 2021 non-residential load to
the sectors and segments according to the proportions in the billing data.
Table 3-6 shows the final allocation of energy to each segment in the commercial sector, as well as
the energy intensity on a square-foot basis. Intensities for each segment were derived from a
combination of the 2021 CBSA and equipment saturations extracted from Avista's database.
Table 3-6 Commercial Sector Control Totals, Washington,2021
Intensity Natural Gas Use 0
Segment Description
Office Traditional office-based businesses including finance, 0.53 536,771
insurance, law,government buildings,etc.
Restaurant Sit-down,fast food,coffee shop,food service,etc. 2.60 747,786
Retail Department stores,services, boutiques,strip malls etc. 0.79 1,547,664
Grocery Supermarkets,convenience stores,market,etc. 0.55 125,630
School Day care, pre-school,elementary,secondary schools 0.28 187,678
College College, university,trade schools,etc. 0.59 182,118
Health Health practitioner office, hospital,urgent care centers, 0.99 243,745
etc.
Lodging Hotel, motel,bed and breakfast,etc. 0.67 370,063
Warehouse Large storage facility, ref rigerated/un refrigerated 0.57 688,567
warehouse
Catchall for buildings not included in other segments,
Miscellaneous includes churches,recreational facilities, public 0.95 2,035,100
assembly,correctional facilities,etc.
Total 0.78 6,665,122
Figure 3-8 shows the distribution of annual natural gas consumption by segment across all
commercial buildings. The three segments with the highest natural gas usage in 2021 are
miscellaneous(30%), retail(23%), and restaurant(11%).
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Figure 3-8 Commercial Natural Gas Use by Segment, Washington,2021
aneous
0% Ark
ilAi
Warehouse
10%
Lodging - _ Grocery
6% College 20�0
Health 30,1,School
4% 3%
Figure 3-9 shows the distribution of natural gas consumption by end use for the entire commercial
sector. Space heating is the largest end use, followed by water heating and food preparation. The
miscellaneous end use is quite small, as expected.
Figure 3-9 Commercial Sector Natural Gas Use by End Use, Washington,2021
Miscellaneous
6%
Food Preparation 11
14%
Water Heating F Space
22%
Figure 3-10 presents average natural gas intensities by end use and segment. In Washington,
restaurants use the most natural gas in the service territory.Avista customer account data informed
the market profile by providing information on saturation of key equipment types. Secondary data
was used to develop estimates of energy intensity and square footage and fill in saturations for any
equipment types not included in the database.
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Figure 3-10 Commercial Energy Usage Intensity by End Use and Segment, Washington,2021
Office
Restaurant
Retail -I
Grocery
School Miscellaneous
College ■ Food Preparation
Health Water Heating
Lodging _
Warehouse
■Space Heating
Miscellaneous -
Average Bldg -
0.50 1.00 1.50 2.00 2.50 3.00
therms/sq ft
Table 3-7 shows the average market profile for the commercial sector as a whole, representing a
composite of all segments and buildings.
Table 3-7Average Market Profile for the Commercial Sector, Washington,2021
EUI Intensity Usage
Furnace 52.4% 0.55 0.29 2,485,626
Space Heating Boiler 21.9% 0.66 0.15 1,247,409
Unit Heater 5.9% 0.31 0.02 156,793
Water Heating Water Heater 58.7% 0.29 0.17 1,481,152
Oven 11.3% 0.08 0.01 73,181
Conveyor Oven 5.6% 0.13 0.01 62,609
Double Rack Oven 5.6% 0.20 0.01 95,114
Fryer 8.0% 0.44 0.04 300,472
Food Preparation
Broiler 13.3% 0.12 0.02 133,574
Griddle 17.5% 0.08 0.01 118,981
Range 17.8% 0.07 0.01 113,457
Steamer 1.9% 0.07 0.00 10,828
Commercial Food Prep
0.2% 0.02 0.00 221
Other
Pool Heater 1.0% 0.06 0.00 5,419
Miscellaneous
Miscellaneous 100% 0.04 0.04 383,287
Total 0.78 6,665,122
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Idaho Characterization
The total natural gas consumed by commercial customers in Avista's Idaho service area in 2021 was
3,149,752 dtherm.Table 3-8 shows the final allocation of energyto each segment in the commercial
sector, as well as the energy intensity on a square-foot basis. Intensities for each segment were
derived from a combination of the 2021 CBSA and equipment saturations extracted from Avista's
database.
Table 3-8 Commercial Sector Control Totals, Idaho,2021
Intensity Natural Gas
Segment Description (therms/Sq Use(dtherms)
Office Traditional office-based businesses including finance, 0.53 226,954
insurance, law,government buildings,etc.
Restaurant Sit-down,fast food,coffee shop,food service,etc. 2.60 139,154
Retail Department stores,services,boutiques,strip malls etc. 0.79 959,894
Grocery Supermarkets,convenience stores,market,etc. 0.55 58,138
School Day care,pre-school,elementary,secondary schools 0.28 184,533
College College, university,trade schools,etc. 0.59 179,370
Health Health practitioner office, hospital,urgent care centers, 1.01 102,436
etc.
Lodging Hotel, motel, bed and breakfast,etc. 0.67 170,255
Warehouse Large storage facility,ref rige rated/u n refrigerated 0.57 334,864
warehouse
Catchall for buildings not included in other segments,
Miscellaneous includes churches,recreational facilities, public 0.95 794,154
assembly,correctional facilities,etc.
Total 0.70 3,149,752
Figure 3-11 shows the distribution of annual natural gas consumption by segment across all
commercial buildings. The three segments with the highest natural gas usage in 2021 are retail
(31%), miscellaneous(25%), and warehouse(11%).
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Figure 3-11 Commercial Natural Gas Use by Segment, Idaho,2021
Restaurant
4%
F
.o
25A
Fool"— 'IF
%
Retail
Ig
31%
Lodgin
5% Health CollegeSchool Grocery
3% coo2%
6% 6%
Figure 3-12 shows the distribution of natural gas consumption by end use for the entire commercial
sector. Space heating is the largest end use, followed by water heating and food preparation. The
miscellaneous end use is quite small, as expected.
Figure 3-12 Commercial Sector Natural Gas Use by End Use, Idaho,2021
Miscellaneous
5%
Food Preparation
12%
Water Heating FF
23% Space
FF 60%
hhlh.----..A
Figure 3-13 presents average natural gas intensities by end use and segment. In Idaho, restaurants
use the most natural gas in the service territory.Avista customer account data informed the market
profile by providing information on saturation of key equipment types. Secondary data was used to
develop estimates of energy intensity and square footage and fill in saturations for any equipment
types not included in the database.
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Figure 3-13 Commercial Energy Usage Intensity by End Use and Segment, Idaho,2021
Office -�
Restaurant --�
Retail
Grocery
School ■Miscellaneous
College
-� ■Food Preparation
Health ■Water Heating
Lodging 1 _
Warehouse ■Space Heating
Miscellaneous -
Average Bldg -
0.50 1.00 1.50 2.00 2.50 3.00
therms/sq ft
Table 3-9 shows the average market profile for the commercial sector as a whole, representing a
composite of all segments and buildings.
Table 3-9 Average Market Profile for the Commercial Sector, Idaho,2021
Saturatio EUI Intensity Usage
Furnace 50.1% 0.53 0.26 1,194,251
Space Heating Boiler 24.5% 0.56 0.14 621,861
Unit Heater 6.2% 0.29 0.02 81,760
Water Heating Water Heater 60.5% 0.26 0.16 722,590
Oven 9.7% 0.09 0.01 40,281
Conveyor Oven 4.8% 0.16 0.01 34,461
Double Rack Oven 4.8% 0.24 0.01 52,353
Fryer 6.8% 0.44 0.03 134,342
Food Preparation Broiler 11.1% 0.07 0.01 33,837
Griddle 15.2% 0.05 0.01 33,185
Range 16.0% 0.05 0.01 32,941
Steamer 2.6% 0.04 00.0 4,364
Commercial Food Prep Other 0.3% 0.01 0.00 118
Pool Heater 0.9% 0.05 0.00 2,146
Miscellaneous
Miscellaneous 100% 0.04 0.04 161,261
Total 0.70 3,149,752
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Industrial Sector
Table 3-10 Industrial Sector Control Totals,2021
Segment Intensity Natural Gas Usage
(therms/employee) (dtherms)
Washington Industrial 1,699 266,766
Idaho Industrial 2,327 230,206
Washington Characterization
The total natural gas consumed by industrial customers in Avista's Washington service area in 2021
was 266,766 dtherms. Like in the commercial sector, customer account data was used to allocate
usage among segments. Energy intensity was derived from AEG's Energy Market Profiles database.
Most industrial measures are installed through custom programs, where the unit of measure is not
as necessary to estimate potential.
Figure 3-14 shows the distribution of annual natural gas consumption by end use for all industrial
customers. Two major sources were used to develop this consumption profile. The first was AEG's
analysis of warehouse usage as part of the commercial sector. We begin with this prototype as a
starting point to represent non-process loads. We then added in process loads using our Energy
Market Profiles database,which summarizes usage by end use and process type.
Figure 3-14 Industrial Natural Gas Use by End Use, Washington,2021
Miscellaneous Space Heating
5% I 6%
Process
Lbb.— __.WMA
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Table 3-11 shows the composite market profile forthe Washington industrialsector. Process cooling
is very small and represents niche technologies such as gas-driven absorption chillers.
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Table 3-11 Average Natural Gas Market Profile for the Industrial Sector, Washington,2021
EUI Intensity Usage
End Use Technology Saturation (therms/Sq Ft) (therms/Sq (dtherms)
Furnace 32.3% 103.12 33.3 5,230
Space Heating Boiler 51.5% 103.12 53.2 8,346
Unit Heater 16.2% 103.12 16.7 2,615
Process Boiler 100% 750.42 750.4 117,823
Process Heating 100% 686.11 686.1 107,725
Process -
Process Cooling 100% 6.65 6.7 1,045
Other Process 100% 70.14 70.1 11,012
Miscellaneous Miscellaneous 100% 82.61 82.6 12,971
Total 1,699.1 266,766
Idaho Characterization
The total natural gas consumed by industrial customers in Avista's Idaho service area in 2021 was
230,206 dtherms.
Figure 3-15 shows the distribution of annual natural gas consumption by end use for all industrial
customers. Two major sources were used to develop this consumption profile. The first was AEG's
analysis of warehouse usage as part of the commercial sector. We begin with this prototype as a
starting point to represent non-process loads. We then added in process loads using our Energy
Market Profiles database,which summarizes usage by end use and process type.
Figure 3-15 Industrial Natural Gas Use by End Use,Idaho,2021
Miscellaneous Space Heating
5% I 6%
Process
LIM.— __,WA
Table 3-12 shows the composite market profile forthe industrial sector. Process cooling isvery small
and represents technologies such as gas-driven absorption chillers.
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Table 3-12 Average Natural Gas Market Profile for the Industrial Sector, Idaho,2021
EUI Intensity Usage
End Use Technology Saturation
(therms/Sq Ft) (therms/Sq Ft) (dtherms—
Furnace 32.3% 141.24 45.6 4,513
Space Heating Boiler 51.5% 141.24 72.8 7,203
Unit Heater 16.2% 141.24 22.8 2,257
Process Boiler 100.0% 1,027.79 1,027.8 101,675
Process Heating 100.0% 939.70 939.7 92,961
Process
Process Cooling 100.0% 9.11 9.1 901
Other Process 100.0% 96.06 96.1 9,503
Miscellaneous Miscellaneous 100.0% 113.14 113.1 11,193
Total 2,327.0 230,206
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4 1 Baseline Projection
Prior to developing estimates of energy efficiency potential, AEG developed a baseline end use
projection to quantify the likely future consumption in the absence of any future conservation
programs. The baseline projection is the foundation for the analysis of savings from future
conservation efforts as well as the metric against which potential savings are measured.
The baseline projection quantifies natural gas consumption for each sector,customer segment, end
use and technology. The end use forecast includes the relatively certain impacts of codes and
standards that will unfold over the study timeframe; all such mandates that were defined as of
January 2024 are included.
Other inputs to the projection include:
• 2021 energy consumption based on the market profiles
• Economic growth forecasts(i.e., customer growth, income growth)
• Natural gas price forecasts,trends in fuel shares and equipment saturations, and
Appliance/equipment standards and building codes and purchase decisions
Avista's internally developed sector-level projections for natural gas sales.
The baseline also includes projected naturally occurring energy efficiency during the potential
forecast period. AEG's Load MAP efficiency choice model uses energy and cost data as well as
current purchase trends to evaluate technologies and predict future purchase shares. AEG also
modeled the adoption of electrification measures of natural gas customers and included the future
effects of this reduction of natural gas equipment stock in Avista's territory.These purchase data all
feed into the stock accounting algorithm to predict and track equipment stock and energy usage for
each market segment.
AEG then calculated hourly profiles of the end use projection using a combination of region-specific
Load shapes from the National Renewable Energy Laboratory's(NREL)end use load profiles,Avista's
Load research data and engineering simulations. Shapes were collected at the sector, segment, end
use or technology level where available. These load shapes were then customized to Avista's
seasonal loads and normalized so the value for each hour represents 1/8760th of the year.The energy
from baseline projection for each end use and technology was applied to each shape to compute
hourly profiles.
This chapter presents the baseline projections developed for each sector and state (as well as a
summary),which include projections of annual use in dtherms.Annual energy use for 2021 reflects
weather-normalized values, while future years of energy use reflect normal weather, as defined by
Avista.
Overall Baseline Projection
Washington
Table 4-1 and Error!Reference source not found.summarize the baseline projection for annual use
by sector for Avista's Washington service territory. The forecast shows annual decreases, driven by
fuel switching efforts and legislation in the residential and commercial sectors.
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Table 4-18aseline Projection Summary by Sector, Washington(dtherms)
2045 Change 11,356,811 11,630,212 12,159,351 12,236,470 11,179,884 9,890,243 -12.91%
Commercial 6,665,122 7,218,289 7,667,169 7,663,059 6,384,073 5,059,004 -24.10%
Industrial 266,766 252,241 281,169 287,631 287,771 286,099 7.25%
Total 18,288,700 19,100,743 20,107,689 20,187,160 17,851,728 15,235,347 -16.70%
Figure 4-1 Baseline Projection Summary by Sector, Washington
25,000,000
20,000,000
15,000,000
t
0
10,000,000
5,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
■Residential ■Commercial ■Industrial
Idaho
Table 4-2 and
2045
Residential 5,617,143 5,981,078 6,072,239 6,315,645 7,069,672 7,295,165 29.87%
Commercial 3,149,752 3,415,640 3,595,593 3,562,749 3,758,630 4,144,068 31.57%
Industrial 230,206 182,526 181,383 188,351 185,889 183,603 -20.24%
Total 8,997,101 9,579,244 9,849,215 10,066,745 11,014,191 11,622,835 29.18%
Figure 4-2 summarize the baseline projection for annual use by sector for Avista's Idaho service
territory. The forecast shows modest annual growth, driven by the residential and commercial
sectors.
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Table 4-2 Baseline Projection Summary by Sector, Idaho(dtherms)
Sector 2021 2023 2024 2025 2035 2045
Residential 5,617,143 5,981,078 6,072,239 6,315,645 7,069,672 7,295,165 29.87%
Commercial 3,149,752 3,415,640 3,595,593 3,562,749 3,758,630 4,144,068 31.57%
Industrial 230,206 182,526 181,383 188,351 185,889 183,603 -20.24%
Total 8,997,101 9,579,244 9,849,215 10,066,745 11,014,191 11,622,835 29.18%
Figure 4-2 Baseline Projection Summary by Sector, Idaho
14,000,000
12,000,000
10,000,000
t
8,000,000
0
6,000,000
4,000,000
2,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
■Residential ■Commercial ■Industrial
Residential Sector
Washington Projection
Table 4-3 and Figure 4-3 present the baseline projection for natural gas at the end-use level for the
residential sector.Overall, residential use decreases from 11,356,811 dtherms in 2021 to 9,890,243
dtherms in 2045 (-12.91%). Factors affecting growth include codes and standards affecting the
installation of new gas equipment, as well as a decrease in equipment consumption due to
standards and naturally occurring efficiency.
We model gas-fired fireplaces as secondary heating. These consume energy and may heat a space
but are rarely used as the primary heating technology. As such, they are estimated to be more
aesthetic and less weather-dependent.This end use grows faster than others since new homes are
more likely to install a unit, increasing fireplace stock. Miscellaneous is a very small end use,
including technologies with low penetration, such as gas barbeques.
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Table 4-3 Residential Baseline Projection by End Use, Washington(dtherms)
%Change
Space Heating 9,408,661 9,539,528 10,012,135 10,099,097 9,272,544 8,017,334 -14.79%
Miscellaneous 30,658 31,268 31,334 31,348 31,309 31,262 1.97%
Appliances 387,763 393,126 394,321 395,192 383,108 370,660 -4.41%
Secondary 172,769 169,949 172,549 163,178 88,431 49,878 -71.13%
Heating
Water Heating 1,356,961 1,496,342 1,549,013 1,547,656 1,404,491 1,421,109 4.73%
Total 11,356,811 11,630,212 12,159,351 12,236,470 11,179,884 9,890,243 -12.91%
Figure 4-3 Residential Baseline Projection by End Use, Washington
14,000,000
12,000,000
10,000,000
■Space Heating
8,000,000 ■Secondary Heating
6,000,000 ■Water Heating
■Appliances
4,000,000 ■Miscellaneous
2,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Idaho Projection
Error! Reference source not found. and
P
OW
W
lEnd - 2025 2035 2045
Space Heating 4,715,719 4,948,665 5,055,098 5,213,185 5,871,465 5,901,498 25.15%
Miscellaneous 8,806 9,192 9,363 9,531 11,197 13,144 49.27%
Appliances 113,073 119,819 122,972 126,121 150,686 179,644 58.87%
Secondary 108,339 105,374 97,544 97,482 41,789 17,210 -84.11%
Heating
Water Heating 671,206 798,028 787,262 869,327 994,535 1,183,668 76.35%
Total 5,617,143 5,981,078 6,072,239 6,315,645 7,069,672 7,295,165 29.87%
Figure 4-4 present the baseline projection for natural gas at the end-use level for the residential
sector. Overall, residential use increases from 5,617,143 dtherms in 2021 to 7,295,165 dtherms in
2045, an increase of 29.87%. Avista's customers in the Idaho territory are not affected by the same
codes as those in Washington, and therefore are not restricted in the installation of new gas
equipment.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 4-4 Residential Baseline Projection by End Use, Idaho(dtherms)
End Use 2021 2023 2024 2025 2035 2045
Space Heating 4,715,719 4,948,665 5,055,098 5,213,185 5,871,465 5,901,498 25.15%
Miscellaneous 8,806 9,192 9,363 9,531 11,197 13,144 49.27%
Appliances 113,073 119,819 122,972 126,121 150,686 179,644 58.87%
Secondary 108,339 105,374 97,544 97,482 41,789 17,210 -84.11%
Heating
Water Heating 671,206 798,028 787,262 869,327 994,535 1,183,668 76.35%
Total 5,617,143 5,981,078 6,072,239 6,315,645 7,069,672 7,295,165 29.87%
Figure 4-4 Residential Baseline Projection by End Use,Idaho
8,000,000
7,000,000
6,000,000
t
5,000,000 ■Space Heating
o ■Secondary Heating
4,000,000
■Water Heating
3,000,000 ■Appliances
2,000,000 ■Miscellaneous
1,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Commercial Sector
Washington Projection
Annual natural gas use in the commercial sector decreases 24.10% during the overall forecast
horizon, starting at 6,665,122 dtherms in 2021, and decreasing to 5,059,004 dtherms in 2045. Table
4-5 and Error! Reference source not found. present the baseline projection at the end-use level for
the commercial sector, as a whole. Similar to the residential sector, consumption is decreasing due
to more stringent building codes affecting the installation of new gas equipment.
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Table 4-5 Commercial Baseline Projection by End Use, Washington(dtherms)
Sector 2021 2023 2024 2025 2035 2045 Change
Space Heating 3,886,828 4,531,546 4,927,924 4,941,394 4,034,863 3,004,776 -22.69%
Water Heating 388,706 401,637 405,668 409,277 427,854 424,294 9.16%
Appliances 1,481,152 1,401,713 1,462,912 1,454,023 1,158,843 933,066 -37.00%
Miscellaneous 908,437 883,393 870,665 858,365 760& 696,868 -23.29%
Total 6,665,122 7,218,289 7,667,169 7,663,059 6,384,073 5,059,004 -24.10%
Figure 4-5 Commercial Baseline Projection by End Use, Washington
91000,000
81000,000
71000,000
61000,000
■Space Heating
0 5,000,000
■Water Heating
41000,000 ■Food Preparation
31000,000 ■Miscellaneous
21000,000
11000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Idaho Projection
Annual natural gas use in the Idaho commercial sector grows 31.57% during the forecast horizon,
starting at 3,149,752 dtherms in 2021, and increasingto 4,144,068 dtherms in 2045. Table 4-6 and
Space Heating 1,897,872 2,130,579 2,292,981 2,262,225 2,359$ 71 2,551,388 34.43%
Miscellaneous 163,408 168,369 170,932 173,502 201,461 234,025 43.22%
Water Heating 722,590 739,547 749,078 739,042 751,584 845,247 16.97%
Food 365,882 377,145 382,602 387,980 446,014 513,408 40.32%
Preparation
Total 3,149,752 3,415,640 3,595,593 3,562,749 3,758,630 4,144,068 31.57%
Figure 4-6 present the baseline projection at the end-use level for the commercial sector. Similar to
the residential sector, market size is increasing and usage per square foot is decreasing slightly.
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Table 4-6 Commercial Baseline Projection by End Use,Idaho(dtherms)
End Use 2021 2023 - 2025 2035 2045
MJ ('21-'45)
Space Heating 1,897,872 2,130,579 2,292,981 2,262,225 2,359,571 2,551,388 34.43%
Miscellaneous 163,408 168,369 170,932 173,502 201,461 234,025 43.22%
Water Heating 722,590 739,547 749,078 739,042 751,584 845,247 16.97%
Food 365,882 377,145 382,602 387,980 446,014 513,408 40.32%
Preparation
Total 3,149,752 3,415,640 3,595,593 3,562,749 3,758,630 4,144,068 31.57%
Figure 4-6 Commercial Baseline Projection by End Use, Idaho
4,500,000
4,000,000
3,500,000
3,000,000
■Space Heating
0 2,500,000 ■Water Heating
2,000,000 ■Food Preparation
1,500,000 ■Miscellaneous
1,000,000
500,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Industrial Sector
Washington Projection
Industrial sector usage increases throughout the planning horizon. Table 4-7 and
End Use 2021 2023 2024 2025 2035 2045 %Change Heating 16,191 17,429 20,527 21,389 19,525 17,853 10.26%
Miscellaneous 12,971 13,957 14,216 14,376 14,485 14,485 11.67%
Process 237,604 220,855 246,427 251,865 253,761 253,761 6.80%
Total 266,766 252,241 281,169 287,631 287,771 286,099 7.25%
Figure 4-7 present the projection at the end-use level. Overall, industrial annual natural gas use
increases from 266,766 dtherms in 2021 to 286,099 dtherms in 2045, an increase of 7.25%.
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Table 4-7 Industrial Baseline Projection by End Use, Washington(dtherms)
Space Heating 16,191 17,429 20,527 21,389 19,525 17,853 10.26%
Miscellaneous 12,971 13,957 14,216 14,376 14,485 14,485 11.67%
Process 237,604 220,855 246,427 251,865 253,761 253,761 6.80%
Total 266,766 252,241 281,169 287,631 287,771 286,099 7.25%
Figure 4-71ndustrial Baseline Projection by End Use, Washington
350,000
300,000
250,000
200,000
■Space Heating
150,000 ■Process
■Miscellaneous
100,000
50,000
1-4 N M Ln w r` 00 M O c1 N M It N w r` 00 a) O "q N M �t Ln
O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N
Idaho Proiection
Industrial annual natural gas use decreases from 230,206 dtherms in 2021 to 183,603 dtherms in
2045, a decrease of 20.24%.Table 4-8 and
2045End Usle MVPMW202V 2024 MRr025 2035
Space Heating 13,972 15,279 15,631 16,971 14,716 12,666 -9.35%
Miscellaneous 11,193 10,845 10,849 10,847 10,834 10,819 -3.34%
Process 205,041 156,403 154,903 160,533 160,339 160,117 -21.91%
Total 230,206 182,526 181,383 188,351 185,889 183,603 -20.24%
Figure 4-8 present the projection at the end-use level.
Table 4-8 Industrial Baseline Projection by End Use,Idaho(dtherms)
0•
Space Heating 13,972 15,279 15,631 16,971 14,716 12,666 -9.35%
Miscellaneous 11,193 10,845 10,849 10,847 10,834 10,819 -3.34%
Process 205,041 156,403 154,903 160,533 160,339 160,117 -21.91%
Total 230,206 182,526 181,383 188,351 185,889 183,603 -20.24%
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Figure 4-8 Industrial Baseline Projection by End Use, Idaho
300,000
250,000
200,000
t
o 150,000 ■Space Heating
■Process
100,000 ■Miscellaneous
50,000
ci N M 1:t Ln w r` 00 Ql O ci N M ItT Ln w r` 00 a) O ci N M -Zl* Ln
N N N N N N N N N CO M M Cn M M M M M M 'zT KT �* 1:T V �*
O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N
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5 1 Conservation Potential
This chapter presents the conservation potential across all sectors for Avista's Washington and
Idaho territories. Conservation potential includes every measure considered in the measure list,
regardless of delivery mechanism (program implementation, etc.). Year-by-year annual energy
savings are available in the LoadMAP model and measure assumption summary, provided to Avista
at the conclusion of the study. Please note that all savings are at the customer site.
Washington Overall Energy Efficiency Potential
Error! Reference source not found. and Figure 5-1 summarize the conservation savings in terms of
annual energy use for all measures for four levels of potential relative to the baseline projection.
45.0%
■Achievable Economic Potential l
40.0% r
■Achievable Technical Potential I
35.0% i
■Technical Potential [`
(D 30.0%
c
25.0%
CO
CO 20.0%
0
15.0%
10.0%
5.0% MM
0.0%
2026 2027 2030 2035 2045
Figure 5-2 displays the cumulative energy conservation forecasts, which reflect the effects of
persistent savings in prior years and new savings.
Technical Potential reflects the adoption of all conservation measures regardless of cost-
effectiveness. Efficient equipment makes up all lost opportunity installations and all retrofit
measures are installed, regardless of achievability. First-year savings are 420,042 dtherms, or
2.1%of the baseline projection. Cumulative savings in 2045 are 5,974,486 dtherms, or 39.2%of
the baseline.
Achievable Technical Potential refines Technical Potential by applying market adoption rates to
each measure. The market adoption rates estimate the percentage of customers who would be
likely to select each measure given market barriers, customer awareness and attitudes, program
maturity, and other factors that affect market penetration of conservation measures. First-year
savings are 245,009 dtherms, or 1.2%of the baseline projection. Cumulative savings in 2045 are
5,183,435 dtherms, or 34.0%of the baseline.
TRC Achievable Economic Potential refines Achievable Technical Potential by applying the TRC
economic cost-effectiveness screen, which compares lifetime energy benefits to the total
customer and utility costs of delivering the measure through a utility program, including
monetized non-energy impacts. For the TRC, AEG also applied (1) benefits for non-gas energy
savings, such as electric HVAC savings for weatherization, (2)the NWPCC's calibration credit to
space heating savings to reflect that additionalfuels may be used as a supplemental heat source
within an average home, and (3) a 10% conservation credit to avoided costs per the NWPCC
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
methodologies. First-year savings are 71,740 dtherms, or 0.4% of the baseline projection.
Cumulative savings in 2045 are 1,601,274 dtherms, or 10.5%of the baseline.
Table 5-1 Summary of Energy Efficiency Potential, Washington
Baseline Forecast(dtherms) 20,130,837 20,175,109 19,396,729 17,851,728 15,235,347
Cumulative Savings(dtherms)
TRC Achievable Economic Potential 71,740 155,226 448,283 1,028,874 1,601,274
Achievable Technical Potential 245,009 560,714 1,575,447 3,599,528 5,183,435
Technical Potential 420,042 884,857 2,154,937 4,498,938 5,974,486
Energy Savings(%of Baseline) '
TRC Achievable Economic Potential 0.4% 0.8% 2.3% 5.8% 10.5%
Achievable Technical Potential 1.2% 2.8% 8.1% 20.2% 34.0%
Technical Potential 2.1% 4.4% 11.1% 25.2% 39.2%
Figure 5-1 Cumulative Energy Efficiency Potential as%of Baseline Projection, Washington
45.0%
■Achievable Economic Potential
40.0%
■Achievable Technical Potential
35.0%
■Technical Potential
(D 30.0%
c
m
00 20.0%
0
15.0%
10.0%
5.0% Mdo
0.0%
2026 2027 2030 2035 2045
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 5-2 Baseline Projection and Energy Efficiency Forecasts, Washington
25,000,000
20,000,000
15,000,000
0
a�
L
p 10,000,000
0
0 Baseline Forecast
U 5,000,000 Achievable Economic Potential
Achievable Technical Potential
Technical Potential
0
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Idaho Overall Energy Efficiency Potential
Table 5-2 and Figure 5-3 summarize the conservation savings in terms of annual energy use for all
measures for four levels of potential relative to the baseline projection. Figure 5-4 displays the
cumulative energy conservation forecasts, which reflect the effects of persistent savings in prior
years in addition to new savings.
Technical Potential first-year savings in 2023 are 161,379 dtherms, or 1.5% of the baseline
projection. Cumulative savings in 2045 are 2,509,059 dtherms, or 21.6%of the baseline.
Achievable Technical Potential first-year savings are 95,484 dtherms, or 0.9% of the baseline
projection. Cumulative savings in 2045 are 2,019,632 dtherms, or 17.4%of the baseline
UCT Achievable Economic Potential first-year savings are 26,527 dtherms, or 0.2% of the
baseline projection. Cumulative savings in 2045 are 600,730 dtherms, or 5.2%of the baseline
Table 5-2 Summary of Energy Efficiency Potential,Idaho
92030 0 2035 2045
Baseline Forecast(dtherms) 10,563,771 10,646,120 10,792,588 11,014,191 11,622,835
Cumulative Savings(dtherms)
UCT Achievable Economic Potential 26,257 60,181 141,546 355,518 600,730
Achievable Technical Potential 95,484 210,216 613,432 1,493,222 2,019,632
Technical Potential 161,379 338,723 843,810 1,918,908 2,509,059
Energy Savings(%of Baseline)
UCT Achievable Economic Potential 0.2% 0.6% 1.3% 3.2% 5.2%
Achievable Technical Potential 0.9% 2.0% 5.7% 13.6% 17.4%
Technical Potential 1.5% 3.2% 7.8% 17.4% 21.6%
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Figure 5-3 Cumulative Energy Efficiency Potential as%of Baseline Projection,Idaho
25.0%
■Achievable Economic Potential
20.0% ■Achievable Technical Potential
■Technical Potential
aD
15.0%
6
m
m_
° 10.0%
0
5.0%
0.0%
2026 2027 2030 2035 2045
Figure 5-4 Baseline Projection and Energy Efficiency Forecasts, Idaho
14,000,000
12,000,000
10,000,000
0 8,000,000
a
6,000,000
c
0 4,000,000 Baseline Forecast
Achievable Economic Potential
2,000,000 Achievable Technical Potential
Technical Potential
0
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
6 1 Sector-Level Energy Efficiency Potential
This chapter provides energy efficiency potential at the sector level.
Residential Sector
Washington Potential
Error!Reference source not found. and
Figure 6-1 summarize the energy efficiency potential for the residential sector. In 2026, TRC
achievable economic potential is 19,132 dtherms, or 0.2% of the baseline projection. By 2045,
cumulative savings are 694,094 dtherms, or 7.0%of the baseline.
Table 6-1 Residential Energy Conservation Potential Summary, Washington
0•
Baseline Forecast(dtherms) 12,180,331 12,226,885 11,857,137 11,179,884 9,890,243
Cumulative Savings(dtherms)
TRC Achievable Economic Potential 19,132 45,189 150,548 424,381 694,094
Achievable Technical Potential 178,769 421,508 1,189,255 2,766,099 3,869,722
Technical Potential 302,288 641,042 1,510,653 3,243,233 4,260,407
Energy Savings(%of Baseline)
TRC Achievable Economic Potential 0.2% 0.4% 1.3% 3.8% 7.0%
Achievable Technical Potential 1.5% 3.4% 10.0% 24.7% 39.1%
Technical Potential 2.5% 5.2% 12.7% 29.0% 43.1%
Figure 6-1 Cumulative Residential Potential as%of Baseline Projection, Washington
50.0%
45.0% ■Achievable Economic Potential
40.0% ■Achievable Technical Potential
35.0% ■Technical Potential
30.0%
m 25.0%
w
20.0%
0
15.0%
10.0%
5.0%
0.0% i
2026 2027 2030 2035 2045
Applied Energy Group,Inc.,proudly part of ICF 57 of 105
2025 Natural Gas IRP Appendix 147

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Error! Reference source not found. presents the forecast of cumulative energy savings by end use.
Space heating makes up a majority of potential followed by water heating.
Figure 6-2 Residential TRC Achievable Economic Potential—Cumulative Savings by End Use, Washington
800,000
700,000
600,000
■Space Heating
500,000 Secondary Heating
t
400,000 ■Water Heating
■Appliances
300,000
■Miscellaneous
200,000
100,000
U, lD r, 00 M O -1 N M � Ln lD n 00 M O -1 N M � V1
N N N N N M M M M M M M M M M V V � �* V �
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
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Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Table 6-2 identifies the top 20 residential measures by cumulative 2026 and 2045 savings. Furnaces,
ceiling insulation, clothes washers, and air sealing are the top measures.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-2 Residential Top Measures in 2026 and 2045, TRC Achievable Economic Potential, Washington
2026 2045
Rank Measure/Technology Cumulative %of Cumulative %of
dtherms Total dtherms Total
1 Furnace 6,063 31.7% 252,172 36.3%
2 Insulation-Ceiling Installation 4,872 25.5% 85,451 12.3%
3 Clothes Washer-CEE Tier 2 3,131 16.4% 25,511 3.7%
4 Building Shell-Air Seating(Infiltration Control) 1,063 5.6% 20,339 2.9%
5 Insulation-Ducting 576 3.0% 10,091 1.5%
6 Insulation-Ceiling Upgrade 546 2.9% 9,495 1.4%
7 Stove/Oven 464 2.4% 9,784 1.4%
8 Ducting-Repair and Sealing-Aerosol 419 2.2% 57,284 8.3%
9 Home Energy Management System(HEMS) 410 2.1% 57,291 8.3%
10 Water Heater(<=55 Gal) 368 1.9% 49,898 7.2%
11 Insulation-Wall Cavity Installation 351 1.8% 4,920 0.7%
12 Insulation-Wall Sheathing 215 1.1% 3,030 0.4%
13 Home Energy Reports 186 1.0% 25,435 3.7%
14 Boiler 119 0.6% 9,082 1.3%
15 Water Heater-Drainwater Heat Recovery 117 0.6% 41,161 5.9%
16 Gas Boiler-Thermostatic Radiator Valves 81 0.4% 9,758 1.4%
17 Windows-Low-e Storm Addition 56 0.3% 792 0.1%
18 Ducting-Repair and Sealing 47 0.2% 6,730 1.0%
19 Water Heater-Pipe Insulation 21 0.1% 3,388 0.5%
20 Gas Boiler-Pipe Insulation 14 0.1% 83 0.0%
Subtotal 19,118 99.9% 681,694 98.2%
Total Savings in Year 19,132 100.0% 694,094 100.0%
Idaho Pote�Mal
Table 6-3 and
Figure 6-3 summarize the energy efficiency potential for the residential sector. In 2026, UCT
achievable economic potential is 13,858 dtherms, or 0.2% of the baseline projection. By 2045,
cumulative savings are 244,613 dtherms, or 3.4%of the baseline.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-3 Residential Energy Conservation Potential Summary, Idaho
Baseline Forecast(dtherms) 6,806,909 6,872,961 6,966,076 7,069,672 7,295,165
Cumulative Savings(dtherms)
Achievable Economic UCT Potential 13,858 33,833 63,666 164,876 244,613
Achievable Technical Potential 64,854 146,531 433,389 1,085,990 1,352,671
Technical Potential 101,847 218,656 533,177 1,296,120 1,598,531
Energy Savings(%of Baseline)
Achievable Economic UCT Potential 0.2% 0.5% 0.9% 2.3% 3.4%
Achievable Technical Potential 1.0% 2.1% 6.2% 15.4% 18.5%
Technical Potential 1.5% 3.2% 7.7% 18.3% 21.9%
Figure 6-3 Cumulative Residential Potential as%of Baseline Projection, Idaho
25.0%
■Achievable Economic Potential
20.0% ■Achievable Technical Potential
■Technical Potential
a�
E 15.0%
m
m
10.0%
0
5.0%
0.0% i -
2026 2030 2045
Figure 6-4 presents the forecast of cumulative energy savings by end use. Space heating makes up
a majority of potential followed by water heating.
Applied Energy Group,Inc.,proudly part of ICF 61 of 105
2025 Natural Gas IRP Appendix 151

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 6-4 Residential UCTAchievable Economic Potential-Cumulative Savings by End Use, Idaho
300,000
250,000
■Space Heating
200,000
Secondary Heating
t
0 150,000 ■Water Heating
■Appliances
100,000 ■Miscellaneous
50,000
Ln lD r 00 Ol O -1 N CO 'zZr Ln lD r` 00 M O ci N M �T Ln
N N N N N M m M M ro M M co ro M V �T � K� ZT �
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
Table 6-4 identifies the top 20 residential measures by cumulative 2026 and 2045 savings. Furnaces,
ceiling insulation, clothes washers, and aerators are the top measures.
Table 6-4 Residential Top Measures in 2026 and 2045, TRC Achievable Economic Potential,Idaho
2026 %of 2045 %of
Rank Measure/ . .•
1 Furnace 5,855 42.2% 44,423 18.2%
2 Insulation-Ceiling Installation 3,663 26.4% 69,252 28.3%
3 Clothes Washer-CEE Tier 2 1,862 13.4% 16,871 6.9%
4 Water Heater-Faucet Aerators 716 5.2% 15,641 6.4%
5 Water Heater-Low-Flow Showerheads 670 4.8% 14,319 5.9%
6 Building Shell-Air Sealing(Infiltration Control) 455 3.3% 9,099 3.7%
7 Insulation-Ceiling Upgrade 279 2.0% 5,437 2.2%
8 ENERGY STAR Home Design 153 1.1% 29,219 11.9%
9 Home Energy Reports 104 0.7% 17,067 7.0%
10 Stove/Oven 62 0.5% 5,586 2.3%
11 Ducting-Repair and Sealing-Aerosol 17 0.1% 2,936 1.2%
12 Water Heater-Pipe Insulation 12 0.1% 2,010 0.8%
13 Fireplace 8 0.1% 5,345 2.2%
14 Circulation Pump-Controls 1 0.0% 404 0.2%
Subtotal 13,858 100.0% 237,610 97.1%
Total Savings in Year 13,858 100.0% 244,613 100.0%
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Commercial Sector
Washington Potential
Table 6-5 and
Figure 6-5 summarize the energy conservation potential for the commercial sector. In 2026, TRC
achievable economic potential is 50,960 dtherms, or 0.7% of the baseline projection. By 2045,
cumulative savings are 874,645 dtherms, or 17.3%of the baseline.
Table 6-5 Commercial Energy Conservation Potential Summary, Washington
Baseline Forecast(dtherms) 7,661,189 7,659,040 7,250,905 6,384,073 5,059,004
Cumulative Savings(dtherms)
Achievable Economic TRC Potential 50,960 106,715 289,032 585,542 874,645
Achievable Technical 64,581 135,857 377,308 814,031 1,280,611
Technical Potential 115,750 239,787 633,697 1,232,844 1,675,560
Energy Savings(%of Baseline)
Achievable Economic TRC Potential 0.7% 1.4% 4.0% 9.2% 17.3%
Achievable Technical 0.8% 1.8% 5.2% 12.8% 25.3%
Technical Potential 1.5% 3.1% 8.7% 19.3% 33.1%
Figure 6-5 Cumulative Commercial Potential as%of Baseline Projection, Washington
35.0%
■Achievable Economic Potential
30.0% ■Achievable Technical Potential
25.0% ■Technical Potential
c
20.0%
M
n3
m
0 15.0%
0 10.0%
5.0%
OV d
0.0%
2026 2027 2030 2035 2045
Figure 6-6 presents the cumulative forecast of energy savings by end use. Space heating makes up
a majorityof the potential early, butwater heatingand food preparation equipment upgrades provide
increased savings opportunities in the later years.
Applied Energy Group,Inc.,proudly part of ICF 63 of 105
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 6-6 Commercial TRC Achievable Economic Potential-Cumulative Savings by End Use, Washington
1,000,000
900,000
800,000
700,000
■Space Heating
600,000
o ■Water Heating
500,000
■Food Preparation
400,000
■Miscellaneous
300,000
200,000
100,000
/1 l0 r` 00 M O 1-1 N M V1 1.0 r` 00 M O 14 N M Ln
N N N N N M M M M M M M M M M �* � �t �t �
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
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Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Table 6-6 identifies the top 20 commercial measures by cumulative savings in 2026 and 2045.
Demand Controlled Ventilation and Destratification Fans are the top measures, providing space
heating savings, followed by Strategic Energy Management and Retrocommissioning and several
HVAC and space heating measures, along with water heater controls.
Table 6-6 Commercial Top Measures in 2023 and 2035, TRC Achievable Economic Potential, Washington
2026 %of 2045 %of
Rank Measure/Technology Cumulative Total Cumulative Total
dtherms dtherms
1 Ventilation-Demand Controlled 11,512 22.6% 69,390 7.9%
2 Destratification Fans(HVLS) 6,454 12.7% 76,738 8.8%
3 HVAC-Energy Recovery Ventilator 4,873 9.6% 64,414 7.4%
4 Water Heater-Pipe Insulation 4,861 9.5% 33,466 3.8%
5 Strategic Energy Management 3,286 6.4% 44,680 5.1%
6 Retrocommissioning 3,048 6.0% 44,020 5.0%
7 Commercial Laundry-Ozone Treatment 2,105 4.1% 14,530 1.7%
8 Gas Boiler-Stack Economizer 1,900 3.7% 13,246 1.5%
9 Circulation Pump-Controls 1,469 2.9% 9,691 1.1%
10 Gas Boiler-Thermostatic Radiator Valves 1,149 2.3% 20,529 2.3%
11 Water Heater 1,134 2.2% 44,216 5.1%
12 Gas Boiler-Insulate Steam Lines/Condensate 979 1.9% 12,967 1.5%
Tank
13 Gas Boiler-Hot Water Reset 919 1.8% 16,170 1.8%
14 Water Heater-Pre-Rinse Spray Valve 726 1.4% 4,727 0.5%
15 Water Heater-ENERGY STAR Dishwasher(3.0) 606 1.2% 4,162 0.5%
16 Boiler 586 1.1% 21,375 2.4%
17 Gas Boiler-Maintenance 580 1.1% 1,638 0.2%
18 Infiltration Control-Loading Dock Sealing 521 1.0% 5,891 0.7%
19 Gas Boiler-High Turndown Burner 482 0.9% 3,118 0.4%
20 Refrigeration-Heat Recovery 469 0.9% 8,437 1.0%
Subtotal 47,659 93.5% 513,406 58.7%
Total Savings in Year 50,960 100.0% 874,645 100.0%
Idaho Potential
Table 6-7 and
Figure 6-7 summarize the energy conservation potential for the commercial sector. In 2026, UCT
achievable economic potential is 11,641 dtherms, or 0.5% of the baseline projection. By 2045,
cumulative savings are 575,363 dtherms, or 13.9%of the baseline.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-7 Commercial Energy Conservation Potential Summary,Idaho
0-
Baseline Forecast(dtherms) 3,568,688 3,585,222 3,639,395 3,758,630 4,144,068
Cumulative Savings(dtherms) '
Achievable Economic UCT Potential 11,998 25,531 75,251 183,328 342,501
Achievable Technical 29,850 62,110 175,849 398,037 651,225
Technical Potential 58,576 118,140 305,571 611,862 892,159
Energy Savings(%of Baseline)
Achievable Economic UCT Potential 0.3% 0.7% 2.1% 4.9% 8.3%
Achievable Technical 0.8% 1.7% 4.8% 10.6% 15.7%
Technical Potential 1.6% 3.3% 8.4% 16.3% 21.5%
Figure 6-7 Cumulative Commercial Potential as%of Baseline Projection,Idaho
25.0%
■Achievable Economic Potential
20.0% ■Achievable Technical Potential
■Technical Potential
a>
E 15.0%
a3
m
10.0%
0
5.0%
0.0% -
2026 2030 2045
Figure 6-8 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings. Space heating makes up a majority of the potential early, but food preparation
equipment upgrades provide substantial savings opportunities in the later years.
Applied Energy Group,Inc.,proudly part of ICF 66 of 105
2025 Natural Gas IRP Appendix 156

Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Figure 6-8 Commercial UCTAchievable Economic Potential—Cumulative Savings by End Use, Idaho
400,000
350,000
300,000
■Space Heating
250,000
Water Heating
� 200,000
■Food Preparation
150,000
■Miscellaneous
100,000
50,000
Ln lD r` 00 M O -1 N Cn 'T Ln l0 r` 00 Ol O -1 N M 'T Ln
N N N N N M M M M M M M M M M � � � � qt �
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
Table 6-8 identifies the top 20 commercial measures by cumulative savings in 2026 and 2045. Pipe
Insulation is the top measure, followed by HVAC energy recovery ventilator, retrocommissioning,
and boiler economizers.
Applied Energy Group,Inc.,proudly part of ICF 67 of 105
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-8 Commercial Top Measures in 2026 and 2045, TRC Achievable Economic Potential,Idaho
2026 %of 2045 %of
Rank Measure/Technology Cumulative Total Cumulative Total
dtherms dtherms
1 Water Heater-Pipe Insulation 2,212 18.4% 16,126 4.7%
2 HVAC-Energy Recovery Ventilator 1,805 15.0% 30,097 8.8%
3 Retrocommissioning 1,300 10.8% 18,855 5.5%
4 Gas Boiler-Stack Economizer 784 6.5% 6,492 1.9%
5 Circulation Pump-Controls 626 5.2% 3,956 1.2%
6 Commercial Laundry-Ozone Treatment 543 4.5% 4,701 1.4%
7 Gas Boiler-Thermostatic Radiator Valves 498 4.1% 10,130 3.0%
8 Water Heater 494 4.1% 26,886 7.8%
9 Boiler 386 3.2% 14,536 4.2%
10 Gas Boiler-Insulate Steam Lines/Condensate 385 3.2% 5,196 1.5%
Tank
11 Gas Boiler-Hot Water Reset 371 3.1% 6,684 2.0%
12 Fryer 356 3.0% 37,786 11.0%
13 Water Heater-Pre-Rinse Spray Valve 307 2.6% 2,333 0.7%
14 Strategic Energy Management 276 2.3% 5,001 1.5%
15 Water Heater-ENERGY STAR Dishwasher(3.0) 246 2.0% 1,946 0.6%
16 Refrigeration-Heat Recovery 201 1.7% 4,259 1.2%
17 Water Heater-Solar System 192 1.6% 1,622 0.5%
18 Unit Heater 146 1.2% 18,435 5.4%
19 Water Heater-Low-Flow Showerheads 128 1.1% 1,039 0.3%
20 Water Heater-Faucet Aerators/Low Flow Nozzles 117 1.0% 797 0.2%
Subtotal 11,374 94.8% 216,877 63.3%
Total Savings in Year 11,998 100.0% 342,501 100.0%
Industrial Sector
Washington Potential
Table 6-9 and Figure 6-9 summarize the energy conservation potential for the industrial sector. In
2026, TRC achievable economic potential is 1,649 dtherms, or 0.6% of the baseline projection. By
2045, cumulative savings reach 32,536 dtherms, or 11.4% of the baseline. Industrial potential is a
lower percentage of overall baseline compared to the residential and commercial sectors. While
large, custom process optimization and controls measures are present in potential, these are not
applicable to all processes, which limits potential at the technical level.Additionally, the remaining
customers are smaller and tend to have lower process end-use shares, further lowering industrial
potential.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-9 Industrial Energy Conservation Potential Summary, Washington
i
Baseline Forecast(dtherms) 289,317 289,184 288,687 287,771 286,099
Cumulative Savings(dtherms)
Achievable Economic TRC Potential 1,649 3,322 8,703 18,951 32,536
Achievable Technical 1,659 3,349 8,884 19,399 33,102
Technical Potential 2,004 4,027 10,587 22,861 38,519
Energy Savings(%of Baseline)
Achievable Economic TRC Potential 0.6% 1.1% 3.0% 6.6% 11.4%
Achievable Technical 0.6% 1.2% 3.1% 6.7% 11.6%
Technical Potential 0.7% 1.4% 3.7% 7.9% 13.5%
Figure 6-9 Cumulative Industrial Potential as%of Baseline Projection, Washington
16.0%
■Achievable Economic Potential
14.0%
■Achievable Technical Potential
12.0% ■Technical Potential
10.0%
m 8.0%
0
0
6.0%
4.0%
2.0%
0.0%
2026 2027 2030 2035 2045
Figure 6-10 presents the forecast of cumulative energy savings by end use.
Applied Energy Group,Inc.,proudly part of ICF 69 of 105
2025 Natural Gas IRP Appendix 159

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 6-101ndustrial TRC Achievable Economic Potential—Cumulative Savings by End Use, Washington
35,000
30,000
25,000
■Space Heating
20,000 ■Process
0
■Miscellaneous
15,000
10,000
5,000
2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Applied Energy Group,Inc.,proudly part of ICF 70 of 105
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Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Table 6-10 identifies the top 20 industrial measures by cumulative 2026 and 2045 savings. Process
Heat Recovery and Process Boiler control measures have the largest potential savings.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-10 Industrial Top Measures in 2026 and 2045, TRC Achievable Economic Potential, Washington
2026 2045
Rank Measure/Technology Cumulative %of Cumulative %of
dtherms Total dtherms Total
1 Process-Heat Recovery 806 48.9% 15,072 46.3%
2 Process Boiler-Steam Trap Replacement 208 12.6% 3,931 12.1%
3 Retrocommissioning 100 6.1% 1,942 6.0%
4 Strategic Energy Management 95 5.8% 2,145 6.6%
5 Process Boiler-Maintenance 81 4.9% 246 0.8%
6 Process Boiler-Insulate Steam Lines/Condensate 68 4.1% 1,289 4.0%
Tank
7 Process Boiler-High Turndown Burner 65 4.0% 585 1.8%
8 Process Boiler-Stack Economizer 57 3.5% 496 1.5%
9 Process-Insulate Heated Process Fluids 54 3.3% 1,078 3.3%
10 Destratification Fans(HVLS) 48 2.9% 749 2.3%
11 Process Boiler-Insulate Hot Water Lines 29 1.7% 541 1.7%
12 Process Boiler-Burner Control Optimization 17 1.0% 2,896 8.9%
13 Ventilation-Demand Controlled 15 0.9% 103 0.3%
14 Unit Heater 5 0.3% 539 1.7%
Subtotal 1,649 100.0% 31,612 97.2%
Total Savings in Year 1,649 100.0% 32,536 100.0%
Idaho Potential
Table 6-11 and
Figure 6-11 summarize the energy conservation potential for the industrial sector. In 2026, UCT
achievable economic potential is 401 dtherms, or 0.2% of the baseline projection. By 2045,
cumulative savings reach 13,615 dtherms, or 7.4% of the baseline. Industrial potential is a lower
percentage of overall baseline compared to the residential and commercial sectors. While large,
custom process optimization and controls measures are present in potential, these are not
applicable to all processes which limits potential at the technical level. Additionally, since the
largest customers were excluded from this analysis due to their status as transport-only customers
making them ineligible to participate in energy efficiency programs for the utility, the remaining
customers are smaller and tend to have lower process end-use shares, further lowering industrial
potential.
Applied Energy Group,Inc.,proudly part of ICF 72 of 105
2025 Natural Gas IRP Appendix 162

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 6-11 Industrial Energy Conservation Potential Summary, Idaho
0•
Baseline Forecast(dtherms) 188,175 187,937 187,118 185,889 183,603
Cumulative Savings(dtherms)
Achievable Economic UCT Potential 401 818 2,628 7,313 13,615
Achievable Technical 779 1,575 4,194 9,195 15,736
Technical Potential 957 1,926 5,062 10,926 18,369
Energy Savings(%of Baseline)
Achievable Economic UCT Potential 0.2% 0.4% 1.4% 3.9% 7.4%
Achievable Technical 0.4% 0.8% 2.2% 4.9% 8.6%
Technical Potential 0.5% 1.0% 2.7% 5.9% 10.0%
Figure 6-11 Cumulative Industrial Potential as%of Baseline Projection,Idaho
12.0%
■Achievable Economic Potential
10.0% ■Achievable Technical Potential
8.0% ■Technical Potential
0
a)c
rn
m 6.0%
0
0
4.0%
2.0%
0.0% -
2026 2030 2045
Figure 6-12 presents forecasts of energy savings by end use as a percent of total annual savings and
cumulative savings.
Applied Energy Group,Inc.,proudly part of ICF 73 of 105
2025 Natural Gas IRP Appendix 163

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 6-12Industrial UCTAchievable Economic Potential—Cumulative Savings by End Use,Idaho
16,000
14,000
12,000
10,000 ■Space Heating
t
o ■Process
8,000
■Miscellaneous
6,000
4,000
2,000
2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Table 6-12 identifies the top 20 industrial measures by cumulative 2026 and 2045 savings.
Table 6-12 Industrial Top Measures in 2026 and 2045, UCTAchievable Economic Potential, Idaho
2026 2045
dtherms Total dtherms Total
1 Process Boiler-Steam Trap Replacement 96 24.0% 1,816 13.3%
2 Retrocommissioning 47 11.8% 915 6.7%
3 Strategic Energy Management 45 11.3% 1,012 7.4%
4 Process Boiler-Maintenance 38 9.4% 116 0.8%
5 Process Boiler-Insulate Steam Lines/Condensate 31 7.8% 601 4.4%
Tank
6 Process Boiler-High Turndown Burner 30 7.5% 272 2.0%
7 Destratification Fans(HVLS) 28 7.1% 400 2.9%
8 Process Boiler-Stack Economizer 26 6.6% 232 1.7%
9 Process-Insulate Heated Process Fluids 25 6.3% 497 3.7%
10 Process Boiler-Insulate Hot Water Lines 13 3.3% 254 1.9%
11 Ventilation-Demand Controlled 8 2.1% 41 0.3%
12 Process Boiler-Burner Control Optimization 8 1.9% 1,347 9.9%
13 Unit Heater 4 1.0% 417 3.1%
Subtotal 401 100.0% 7,918 58.2%
Total Savings in Year 401 100.0% 13,615 100.0%
Applied Energy Group,Inc.,proudly part of ICF
2025 Natural Gas IRP Appendix 164

Avista Natural Gas Conservation PotentialAssessment for 2026-2045
7 1 Demand Response Potential
This study is the second time AEG has estimated demand response (DR) potential for natural gas in
the Avista territory. Natural gas DR is an emerging market with only a few programs offered in the US.
To estimate potential,AEG referenced the most current natural gas DR program data and addressed
gaps utilizing information from the electric DR study.
The current study provides demand response potential and cost estimates for the 25-year planning
horizon (2026-2045)to inform the development of Avista's 2025 IRP. Through this assessment,AEG
sought to develop reliable estimates of the magnitude, timing, and costs of DR resources likely
available toAvista overthe planning horizon.The analysis focuses on resources assumed achievable
during the planning horizon, recognizing known market dynamics that may hinder resource
acquisition. DR analysis results will also be incorporated into subsequent DR planning and program
development efforts.
Study Approach
Figure 7-1 outlines the analysis approach used to develop potential and cost estimates, with each
step described in more detail in the subsections that follow.
Figure 7-1 Demand Response Analysis Approach
Baseline
F-Achieabo
Projection
•Segment by •Use DR • DLCMeasure vle
Sector, Segmentation Options Technical
Geography •Account for • DR Economic •Realistic
and Size Interactions Options Achievable
•Align with EE • DSR Options
Study
AEG estimated demand response potential across the following scenarios:
Achievable Technical Potential or Stand Alone. In this scenario, program options are treated
as if they are the only programs running in the Avista territory and are viewed in a vacuum.
Potential demand savings cannot be added in this scenario since it does not account for program
overlap.
Realistic Achievable Potential or Integrated.'In this scenario, the program options are treated
as if the programs were run simultaneously. To account for participation, overlap across
programs that make use of the same end-use, a program hierarchy is employed. For programs
that affect the same end use, the model selects the most likely program a customer would
participate in, and eligible participants were chosen for that program first.The remaining pool of
eligible participants will then be available to participate in the secondary program.This scenario
allows for potential to be added up as it removes any double counting of savings.
Market Characterization
The first step in the DR analysis was to segment customers by service class and develop
characteristics for each segment.The two relevant characteristics for DR potential analysis are end-
' For this study, the participation in the considered programs is not expected to overlap.Therefore, only the
Realistic Achievable Potential is shown.
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use saturations of the controllable equipment types in each market segment and coincident peak
demand in the base year. Market characteristics, including equipment saturation and base year
peak consumption, are consistent with the energy efficiency analysis (see Chapter 2 for more
information on the market profiles).
As in previous studies,AEG used Avista's rate schedules as the basis for customer segmentation by
state and customer class.Table 7-1 summarizes the market segmentation developed for this study.
Table 7-1 Market Segmentation
Market Segmentation Description
Dimensions Variable
Washington
1 State Idaho
Oregon
Residential
2 Customer Class Commercial
Industrial
Baseline Forecast
Once the customer segments were defined and characterized, AEG developed the baseline
projection. Load and consumption characteristics, including customer counts and peak-hour
demand values,were provided byAvista and aligned with the natural gas energy efficiency analysis.
Customer Counts
Avista provided actual customer counts by rate schedule for Washington and Idaho over the 2019-
2023 timeframe and forecasted customer counts over the 2024-2028 period. AEG used this data to
calculate the growth rates by customer class across the final two forecasted years, and projected
customer counts through 2045. The average annual customer growth rate for all sectors was 0.6%
in Washington and 0.7%in Idaho.
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Table 7-2 Baseline Customer Forecast by Customer Class, Washington
Residential 161,986 161,986 161,986 161,986 161,986
Commercial 15,232 15,220 15,208 15,125 15,006
Industrial 90 89 88 82 73
Table 7-3 Baseline Customer Forecast by Customer Class,Idaho
Residential 88,643 90,152 91,615 102,964 121,658
Commercial 10,111 10,217 10,318 11,082 12,273
Industrial 67 67 67 67 67
Table 7-4 Baseline Customer Forecast by Customer Class,Oregon
04
Residential 96,198 96,715 97,162 100,930 106,568
Commercial 12,170 12,209 12,242 12,521 12,930
Industrial 25 25 25 25 25
Winter Peak Load Forecasts by State
Winter peak load forecasts were developed by state and customer class by multiplying the per
customer peak-hour demand values by class by the forecasted customer counts. Table 7-5 shows
the winter system peak for selected future years. The system peak is expected to increase by 7%
between 2026 and 2045.
Table 7-5 Baseline February Winter System Peak Forecast(Dth @Generation)by State
State 2026 2027 2028 2035 2045
Washington 9,217 9,207 9,193 9,094 8,956
Idaho 5,060 5,115 5,185 5,611 6,288
Oregon 4,090 4,107 4,121 4,240 4,416
Grand Total 18,367 18,428 18,500 18,946 19,660
Figure 7-2 shows the contribution to the estimated system coincident winter peak by state. In 2026,
system peak load for the winter is 18,367 dtherms at generation.Washington contributes 50%to the
winter system peak, while Idaho and Oregon contribute 28% and 22%, respectively. Winter
coincident peak load is expected to grow by an average of 0.4%annually from 2026-2045.
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Figure 7-2 Coincident Peak Load Forecast by State(Winter)
25,000
20,000
15,000
0
10,000
5,000
2026 2027 2030 2035 2045
■Washington ■Idaho —Oregon
Characterize Demand Response Program Options
Next, AEG identified and described the viable DR programs for inclusion in the analysis and
developed assumptions for key program parameters, including per customer impacts, participation
rates, program eligibility, and program costs. AEG considered the characteristics and applicability
of a comprehensive list of options available that could be feasibly run in Avista's territory. Once a list
of DR options was determined,AEG characterized each option.
Each selected option is described briefly below.
Program Descriptions
DLC Smart Thermostats—Heating
These programs use the two-way communicating ability of smart thermostats to cycle heating end
uses on and off during events.The program targets Avista's Residential and Commercial customers
with qualifying equipment in Washington, Idaho, and Oregon.This program is assumed to be a Bring
Your Own Thermostat(BYOT) program;therefore, no equipment or installation costs were estimated
and is only considered for the residential sector in the state of Washington for this study due to AMI
constraints.
Third Party Contracts
Third Party Contracts are assumed to be available for large commercial and industrial customers
and is considered for all three states in the Avista territory for this study.This program is based on a
firm curtailment strategy targeting large process and heating loads. It is also assumed that
participating customers will agree to reduce demand by a specific amount or curtail consumption to
a predefined level at the time of an event. In return,they receive a fixed incentive payment in the form
of capacity credits or reservation payments(typically expressed as$/therm-month or$/therm-year).
Customers are paid to be on call even though actual load curtailments may not occur.The amount
of the capacity payment typically varies with the load commitment level. In addition to the fixed
capacity payment, participants typically receive a payment for gas reduction during events. Because
it is a firm, contractual arrangement for a specific level of load reduction, enrolled loads represent a
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firm resource and can be counted toward installed capacity requirements. Penalties may be
assessed for under-performance or non-performance. Events may be called on a day-of or day-
ahead basis as conditions warrant.
This option is typically delivered by load aggregators and is most attractive for customers with high
natural gas demand and flexibility in their operations. Industry experience indicates that aggregation
of customers with smaller-sized loads is less attractive financially due to lower economies of scale.
In addition, customers with 24x7 operations, continuous processes, or with obligations to continue
providing service(such as schools and hospitals) are not often good candidates for this option.
Behavioral DR
Behavioral DR is structured like traditional demand response interventions, but it does not rely on
enabling technologies, nor does it offer financial incentives to participants. Participants are notified
of an event and simply asked to reduce their consumption during the event window. Generally,
notification occurs the day prior to the event and are deployed utilizing a phone call, email, or text
message. The next day, customers may receive post-event feedback that includes personalized
results and encouragement. This program is assumed to be offered to residential customers only
and is considered for all three states for this study.
Program Assumptions and Characteristics
The key parameters required to estimate the potential for a DR program are participation rate, per-
participant load reduction, and eligibility or end use saturations. The development of these
parameters is based on research findings and a review of available information on the topic,
including national program survey databases, evaluation studies, program reports, and regulatory
filings.AEG's assumptions of these parameters are described below.
Participation Rate Assumptions
Table 7-6 below shows the steady-state participation rate assumptions for each demand side
management(DSM) option as well as the basis for the assumptions.
Table 7-6 DSM Steady-State Participation Rates(Percent of Eligible Customers)
DSM Option Residential Commercial •
Service Service Service
Behavioral 12% PG&E rollout with six waves(2017) -60%of
Electric Behavioral Program Participation
DLC Smart Thermostats NWPC Smart Thermostat cooling
-BYOT 9% assumption -60%of Electric Smart
Thermostat Program Participation
Industry Experience-60%of Electric Third
Third Party Contracts - 5% 13% Party Contracts Program Participation.
Commercial adjusted to reflect challenge
of reducing heating loads
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Load Reduction Assumptions
Table 7-7 presents the per participant load reductions for each DSM option and explains the basis
for these assumptions.
Table 7-7 DSM Per Participant Impact Assumptions
DSM Option ResidentiaL Commercial IndustriaL Basis for Assumption
Service Service Service
Behavioral 2% PG&E Natural Gas Behavioral DR Pilot
rollout with six waves
DLC Smart Con Edison BYOT Smart Thermostat
Thermostats-BYOT 0.8 Therms - Pilot Program results—average savings
per participant
De-rated BYOT Residential impact for
Third Party Contracts - 8% 8% Third Party accounting for less
discretionary load
Other Cross-cutting Assumptions
In addition to the above program-specific assumptions,there are three that affect all programs:
Discount rate. A nominal discount rate of 6.51%was used to calculate the net present value of
costs over the useful life of each DR program.All cost results are shown in nominal dollars.
Line losses. Avista provided forecasted line loss factors averaging 5.6% which AEG used to
convert estimated demand savings at the customer meter level to the generator level. Results in
the next section are reported at the generator level.
Shifting and saving. Each program varies in the way energy is shifted or saved throughout the
day. For example, customers on the DLC Central AC program are likely to pre-cool their homes
prior to the event and turn their AC units back on after the event(snapback effect).The results in
this report only show the savings during the event window and not before and after the event.
DR Potential Results
This section presents analysis results for demand savings and levelized costs for all considered DR
programs.As mentioned above,the integrated and stand-alone results are synonymous.Therefore,
only one set of results are shown in this section assuming all programs can be run simultaneously.
Summary TOU Opt-in Scenario
Table 7-8 and Figure 7-3 show the total winter demand savings for selected years. These savings
represent integrated savingsfrom all available DR options in Avista's Washington, Idaho,and Oregon
service territories.
The total potential savings are expected to increase from 36 Dth in 2026 to 287 Dth by 2045.The
percentage of system peak increases from 0.2%in 2026 to 1.5% by 2045.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table 7-8 Summary of Integrated Potential(Dtherms @ Generator)
04
Baseline Forecast 18,367 18,428 18,500 18,946 19,660
Achievable Potential 36 86 179 262 287
Achievable Potential(%of baseline) 0.2% 0.5% 1.0% 1.4% 1.5%
Potential Forecast 18,331 18,342 18,321 18,684 19,374
Figure 7-3 Summary of Integrated Potential(Dtherms @ Generator)
20,000 19,660
19,500
19,000 19,374
Dth 18,367
18,500 I
18,000 L 18,331
17,500
,f) ti6� ti ti ti ti ti���
Baseline Forecast Potential Forecast
Results
Key findings include:
The largest potential option is DLC Smart Thermostats - BYOT, contributing 236 dtherms by 2045.
Behavioral and Third Party Contracts program options offer a potential reduction in peak natural
gas demand of 30 and 21 dtherms, respectively by 2045.
Potential by DSM Option
Figure 7-4 and Table 7-9 show the total winter demand savings from individual DR options for
selected years. These savings represent integrated savings from all available DR options in Avista's
Washington, Idaho, and Oregon service territories. Currently Washington is the only state in the
Avista territory with AMI for natural gas customers. Due to the increased effectiveness of a Smart
Thermostat program with use of AMI,the DLC Smart Thermostats—BYOT Program is only considered
for the state of Washington. Even so, the DLC Smart Thermostats — BYOT Program is projected to
save the most of all programs at 236 dtherms by 2045 while the Behavioral DR and Third Party
Contracts Programs are projected to reduce peak demand by 30 and 21 dtherms by 2045,
respectively.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 7-4 Summary of Potential by Option-(Dtherms @ Generator)
350
300
250
Achievable
Potential(Dth) 200
150
100
50
2026 2027 2028 2035 2045
■Behavioral ■ DLC Smart Thermostats-BYOT ■Third Party Contracts
Table 7-9 Summary of Potential by Option—(Dtherms @ Generator)
Summer Potential 2026 2027 2028 2035 2045
Baseline Forecast 18,367 18,428 18,500 18,946 19,660
Achievable Potential 36 86 179 262 287
Achievable Potential(%) 0.2% 0.5% 1.0% 1.4% 1.5%
Behavioral 7 11 21 28 30
DLC Smart Thermostats-BYOT 19 59 138 213 236
Third Party Contracts 10 16 20 20 21
Potential by Sector
Table 7-10, Table 7-11, and Table 7-12 show the total winter demand savings by class for
Washington, Idaho, and Oregon respectively.Washington is projected to save 128 dtherms(1.4%of
winter system peak demand) by 2045, Idaho is projected to save 94 dtherms(1.5%of winter system
peak demand) by 2045, and Oregon is projected to save 64 dtherms (1.5% of winter system peak
demand) by 2045.
The residential sector contributes 87%of the total load across all three states while commercial and
industrial contribute 15% and 7% respectively. This is due primarily to the low number of industrial
natural gas customers in Avista's territory.
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Table 7-10 Potential by Sector-Dtherms @Generator,Washington
Baseline Forecast 9,217 9,207 9,193 9,094 8,956
Achievable Potential(Dth) 22 49 93 125 128
Residential 16.4 40 82 115 118
Commercial 4.9 8 10 10 10
Industrial 0.3 1 1 1 1
Table 7-11 Potential bySector-Dtherms @Generator,Idaho
2026 20271 1 14
Baseline Forecast 5,060 5,115 5,185 5,611 6,288
Achievable Potential(Dth) 8 21 50 80 94
Residential 5.5 17 44 74 88
Commercial 2.4 4 5 5 5
Industrial 0.3 1 1 1 1
Table 7-12 Potential bySector-Dtherms @Generator,Oregon
2026 20271 1 14
Baseline Forecast 4,090 4,107 4,121 4,240 4,416
Achievable Potential(Dth) 6 16 37 57 64
Residential 4.1 12 32 53 60
Commercial 2.0 3 4 4 4
Industrial 0.0 0 0 0 0
Figure 7-5 Potential by Sector-Dtherms @Generator,Washington
140
120
100 1117
Industrial
Achievable 80
Potential(Dth) 60 Commercial
40 _ Residential
20 FE ■ ■
2026 2027 2028 2035 2045
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Figure 7-6 Potential by Sector-Dtherms @Generator,Idaho
140
120
100
■ Industrial
Achievable 80
Potential(Dth) 60 _ Commercial
40 Residential
20
2026 2027 2028 2035 2045
Figure 7-7Potential by Sector-Dtherms @Generator,Oregon
140
120
100
■ Industrial
Achievable 80
Potential(Dth) 60 _ Commercial
40 Residential
20 -
2026 2027 2028 2035 2045
Levelized Costs
Table 7-13 presents the Levelized costs per dekatherm of equivalent generation capacity over 2026-
2035 for Washington, Idaho, and Oregon. The ten-year NPV dekatherm potential by program is
shown for reference in the first column.
Keyfindings include:
The Third Party Contracts Program is expected to be the cheapest program to run per dekatherm
savings at approximately$4,429/dekatherm-year. Capacity-based and energy-based payments
to the third-party constitutes the major cost component for this option as well as the cost to the
vendor for program operation.
The Behavioral Program has the highest levelized cost among all the DR program over ten years
at$13,790/dekatherm-year system-wide.The main contributors to the high cost compared to low
savings are O&M and administrative costs.
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Table 7-13 Levelized Program Costs and Potential
Program NPV Dth Potential, Levelized Costs($/Dth)
Behavioral 169.67 $13,789.84
DLC Smart Thermostats-BYOT 579.18 $7,821.25
Third Party Contracts 141.71 $4,429.17
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Avista Natural Gas Conservation PotentialAssessment for 2026-2045
A I Oregon Low-Income Conservation Potential
Background
To support initiatives to serve low-income customers and reduce energy burden in its Oregon natural
gas service territory, Avista Corporation (Avista) engaged Applied Energy Group (AEG)to assess the
energy efficiency potential for Oregon low-income households. This analysis leverages the natural
gas conservation potential assessment (CPA)AEG was already performing for Avista's Washington
and Idaho service territories, incorporating Oregon-specific data to ensure results are directly
applicable to Avista's Oregon low-income customers.
This memo presents a high-level summary of potential results, followed by an overview of AEG's
methodology, identification of key data sources, customer segmentation analysis, and more
detailed potential results.
Results Summary
A summary of the energy efficiency potential for Oregon low-income customers is presented in
Error! Reference source not found.. As shown, achievable and cost-effective energy efficiency
potential represents approximately 6%of baseline sales by 2045.
AEG notes the following considerations in reviewing these results:
The study relied on the best available data from Avista and secondary sources. Sources did not
include on-site assessments of low-income customer equipment efficiency or practices.
Therefore, current conditions and remaining opportunities were estimated using information
about typical characteristics by market segment.
Achievable economic potential was estimated from the Total Resource Cost (TRC) perspective,
consistent with standard cost-effectiveness practices for energy efficiency in Oregon.
Energy efficiency programs serving low-income customers are often not required to be cost-
effective. Achievable technical potential provides an estimate of what could be possible if cost-
effectiveness is not considered.
TableA- 1 Summary of Energy Efficiency Potential
0-
Baseline Forecast(dtherms) 901,274 904,673 896,310 879,805 856,427
Cumulative Savings(dtherms)
Achievable Economic TRC Potential 2,068 4,856 14,095 39,976 51,164
Achievable Technical 9,275 20,777 63,138 155,234 189,919
Technical Potential 13,847 29,842 78,653 186,112 221,549
Energy Savings(%of Baseline)
Achievable Economic TRC Potential 0.2% 0.5% 1.6% 4.5% 6.0%
Achievable Technical 1.0% 2.3% 7.0% 17.6% 22.2%
Technical Potential 1.5% 3.3% 8.8% 21.2% 25.9%
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Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Methodology
AEG used a bottom-up approach to perform the potential analysis,following the steps listed:
1. Perform a customer segmentation analysis to estimate the number of Avista Oregon residential
customers in each housing type and considered low-income, and the energy consumption of each
segment.
2. Perform a market characterization to describe sector-level natural gas use for residential low-income
customers for the base year, 2021. The characterization included extensive use of Avista data and
other secondary data sources from Northwest Energy Efficiency Alliance (NEEA) and the Energy
Information Administration (EIA).
3. Develop a residential baseline projection of energy consumption by segment,end use,and technology
for 2026 through 2045.
4. Define and characterize energy efficiency measures to be applied to all segments and end uses.
5. Estimate technical,achievable technical, and achievable economic energy efficiency potential at the
measure level for 2026 through 2045.
Key Data Sources
AEG used Avista's 2024 Washington and Idaho CPA as the foundation for this assessment. Key
updates from the Washington CPA assumptions to reflectthe Oregon market and potential included:
Input and market characterization data were specific to Avista's Oregon low-income customers.
The CPA model generallyformed the basis for measure cost assumptions and savings estimates.
With the CPA measure list as the starting point, AEG worked with Avista to identify measures in
active programs serving low-income customers, avoiding measures that are inappropriate for
these segments due to costs or other concerns.
The model reflects baseline conditions in alignment with Oregon's state building codes.
Where data gaps existed in Avista's data, AEG relied on national and regional data sources for
assumptions in the potential model. Error! Reference source not found. summarizes key data
sources used and how they informed the study.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table A- 2 Key Data Source Summary
Data Source Used For:
Development of customer counts and energy use for each segment type,
Avista Data comparison baseline forecast,customer counts forecast,presence of
equipment,end use load distribution,economics inputs,scenario
development
US Census American Community
Survey(ACS) Household characteristics in block groups
Northwest Power and Conservation Technical achievable ramp rate library and study methodology
Council's 2021 Power Plan
NEEA's Residential Building Stock
Assessment II(RBSA),Single- Benchmark equipment saturations,normalized end use and equipment
intensity(therms per household)
Family Homes Report 2016-2017
US Energy Information
Administration(EIA)2015 Estimated equipment use per unit,end use distribution of natural gas use
Residential Energy Consumption by segment type, benchmarking equipment presence(saturation)
Survey(RECS)
EIA's 2020 Annual Energy Outlook Reference baseline purchase assumptions, equipment lifetimes and
costs
Customer Segmentation Analysis
To estimate the number of Avista customers in Oregon to include in the low-income assessment,
AEG mapped address data backto corresponding geographic"block groups"in the ACS census data.
Each block groups was then processed to analyze average household size and income, producing a
distribution of households into income buckets for places where Avista customers reside. The low-
income threshold corresponds with 200% of the Federal Poverty Level. The maps in Error!
Reference source not found. shows the distribution of different income groups through Avista's
Oregon service territory.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure A- 1 Income Group Map
Roseburg-Grants Pass-Medford income Group La Grande
All Lwr Income -
-Lowincome
-Under 200%of the Federal Poverty Level
L'
J �
N�
Klamath Falls
vqr
Source Census American Community Survey 2019,provides accurate estimates of household median income,household
and structure type within each block group.
Once the percentage of customers in each housing type and income group was known, AEG used
RBSA data to investigate differences in energy consumption for each grouping, enabling a
comparison of natural gas usage per household across categories. Combining the
geographic/demographic analysis with RBSA data on usage differences by income level, AEG was
able to produce an expanded residential profile with data-driven variation by income group. Error!
Reference source not found.shows the customer energy consumption by income level in the base
year, 2021. While AEG fully characterized the residential customer populations, only low-income
customers are included in the potential analysis.
Table A- 3 Customer Counts and Energy Consumption by Dwelling Type and Income Level,2021
Segment HousehoLds Natural Gas Intensity
Single Family-Regular Income 58,913 3,770,739 64,006
Single Family-Low Income 12,289 662,559 53,917
Multi-Family-Regular Income 7,707 183,230 23,774
Multi-Family-Low Income 4,428 88,679 20,026
Mobile Home-Regular Income 7,066 253,416 35,864
Mobile Home-Low Income 2,197 113,191 51,514
Total 92,600 5,071,813 54,771
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Potential Results
Error! Reference source not found. presents the annual potential savings relative to the baseline
projection. Based on the ramp rates used, a majority of the identified potential is assumed to be
acquired over 10 years.
Table A- 2 Cumulative Energy Efficiency Potential as o of Baseline Projection
30.0%
■Achievable Economic Potential
25.0% ■Achievable Technical Potential
■Technical Potential
20.0%
aD
c
m 15.0%
0
10.0%
5.0%
0.0%
2026 2027 2030 2035 2045
Figure A-3 Achievable Economic Potential, 2045
Potential by Market Segment
presents the percentage of achievable economic
potential in 2045 by market segment and end use. Single family dwellings account for 73% of low-
income achievable economic potential. Space heating accounts for 76%of low-income achievable
economic potential.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure A-3 Achievable Economic Potential,2045
Potential by Market Segment Potential by End Use
Appliances,
2% \ Secondary
Mobile Water Heating,2%
Home Heating,
10% 20%
Space
Figure A- presents a forecast of cumulative achievable economic potential by end use. Space
heating accounts for the majority of potential but declines slightly in the mid-2020s due to a future
furnace standard.
Figure A-4 Cumulative TRC Achievable Economic Potential by End Use
1,200,000
1,000,000
800,000 ■Space Heating
0
600,000 Secondary Heating
■Water Heating
400,000
■Appliances
200,000 ■Miscellaneous
_ .�� ! . . . ■ ■ ■ ■ 111 ■ 11111
l0 n W M O �i N M � Ln W n W M O Ln
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Error! Reference source not found. identifies the top measures by cumulative 2026 and 2036
achievable economic potential. Furnaces, insulation, and clothes washers are the top measures.
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
Table A- 4 Top Measures in 2026 and 2036,Achievable Economic Potential
Rank Measure/Technology Cumulative Total Cumulative Total
1 Furnace 12,297 35.1% 152,477 21.7%
2 Insulation-Ceiling Installation 8,932 25.5% 167,787 23.9%
3 Clothes Washer-CEE Tier 2 4,993 14.2% 40,570 5.8%
4 Building Shell-Air Sealing(InfiltrationControl) 1,517 4.3% 32,651 4.7%
5 Insulation-Ceiling Upgrade 1,143 3.3% 21,155 3.0%
6 Water Heater-Faucet Aerators 716 2.0% 14,393 2.1%
7 Insulation-Ducting 683 1.9% 12,115 1.7%
8 Water Heater-Low-Flow Showerheads 670 1.9% 13,209 1.9%
9 Stove/Oven 543 1.5% 8,638 1.2%
10 Ducting-Repair and Sealing-Aerosol 466 1.3% 49,907 7.1%
11 Home Energy Management System(HEMS) 410 1.2% 43,745 6.2%
12 Insulation-Wall Cavity Installation 375 1.1% 6,404 0.9%
13 Water Heater(< 55 Gal) 368 1.0% 24,632 3.5%
14 Insulation-Wall Cavity Upgrade 365 1.0% 7,027 1.0%
15 Insulation-Wall Sheathing 307 0.9% 5,399 0.8%
Subtotal 33,785 96% 600,110 86%
Total Savings in Year 35,058 100.0% 701,329 100.0%
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Avista Natural Gas Conservation Potential Assessment for 2026-2045
B I Natural Gas Transportation Customer Conservation
Potential
Background
Avista Corporation (Avista) engaged Applied Energy Group (AEG) to assess the conservation
potential at Washington and Oregon natural gas transportation customer' facilities to inform the
extent to which energy efficiency savings at these facilities could help Avista comply with new
regulations. In Washington and Oregon, Avista's transportation customers are currently exempt
from funding energy efficiency programs and thus are not eligible to participate in natural gas energy
efficiency programs administered by Avista and the Energy Trust of Oregon in Washington and
Oregon, respectively.
In Washington, the Washington Utilities and Transportation Commission continues to consider
whether pursuing all cost-effective conservation, as required by Initiative 937, requires utilities to
fund energy efficiency programs for natural gas transportation customers. In Oregon, Executive
Order 20-04,passed in March 2020, limits statewide greenhouse gas emissions from large stationary
sources, transportation fuel, and other liquid and gaseous fuels by new goals established by the
Oregon Department of Environmental Quality (DEQ). The Climate Protection Program (CPP)
formalizes emission reduction requirements for Oregon's natural gas utilities, including the
responsibility for on-site emissions of natural gas transportation customers.
The remainder of this memo presents high-level study results, followed by an overview of AEG's
methodology, identification of key data sources, potential results, and considerations and
recommendations as Avista considers new program options to reach these customers.
Results Summary
Error!Reference source not found.and Error!Reference source not found.summarize the energy
efficiency potential at transportation customer sites in Washington and Oregon, respectively. AEG
notes the following considerations in reviewing these results:
The potential represents expected levels of savings using average assumptions across
customers and equipment. However, a small number of customers represent a majority of
transportation customer consumption (the top 21% of the largest Washington transportation
customers make up roughly 76% of Avista Washington transportation load). Therefore, actual
energy efficiency impacts may vary widely depending on whether these large customers choose
to participate in potential programs and customer-specific characteristics. As such, these
results should be viewed as planning assumptions that are likely to differ in practice.
The study relied on the best available data from Avista and secondary sources, which did not
include on-site assessments of transportation customer equipment efficiency or practices.
Therefore, current conditions and remaining opportunities were estimated using information
about typical characteristics by market segment(i.e., business or industry type).
'Transportation customers are non-residential natural gas consumers, typically large industrial users, who
purchase natural gas from an alternate supplier but use Avista's distribution system to deliver the fuel to their
sites.
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2025 Natural Gas IRP Appendix 183

Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Achievable economic potential was estimated from the Total Resource Cost (TRC) perspective,
consistent with standard cost-effectiveness practices for energy efficiency in Washington and
Oregon.
Table 8-1 Summary Potential Results-Reference Case, Washington
04
Baseline Projection(dtherms) 3,178,623 3,163,094 3,117,080 3,062,121 2,992,666
Cumulative Savings(dtherms)
Achievable Economic Potential 20,752 42,028 110,865 229,109 349,006
Achievable Technical Potential 34,221 66,368 161,137 315,616 462,712
Technical Potential 47,376 91,576 218,534 412,652 585,248
Cumulative Savings(%of Baseline)
Achievable Economic Potential 0.7% 1.3% 3.6% 7.5% 11.7%
Achievable Technical Potential 1.1% 2.1% 5.2% 10.3% 15.5%
Technical Potential 1.5% 2.9% 7.0% 13.5% 19.6%
Table 8-2 Summary Potential Results-Reference Case,Oregon
Baseline Projection(dtherms) 2,613,245 2,608,079 2,592,387 2,572,641 2,545,358
Cumulative Savings(dtherms)
Achievable Economic Potential 12,657 25,566 68,517 151,714 251,405
Achievable Technical Potential 16,434 32,521 83,285 176,741 284,374
Technical Potential 22,040 43,467 109,505 225,146 353,597
Cumulative Savings(%of Baseline)
Achievable Economic Potential 0.5% 1.0% 2.6% 5.9% 9.9%
Achievable Technical Potential 0.6% 1.2% 3.2% 6.9% 11.2%
Technical Potential 0.8% 1.7% 4.2% 8.8% 13.9%
Methodology
AEG used a bottom-up approach to perform the potential analysis,following the steps listed:
1. Perform a customer segmentation analysis to estimate the number of Avista Washington and
Oregon transportation customers in each market segment and the energy consumption of
each segment.
2. Perform a market characterization to describe sector-level natural gas use for transportation
customers for the base year,2021.The characterization included extensive use of Avista data
and other secondary data sources from the US Energy Information Administration (EIA).
3. Develop a baseline projection of energy consumption by segment, end use, and technology
for 2026 through 2045.
4. Define and characterize energy efficiency measures to be applied to all segments and end
uses.
5. Estimate technical, achievable technical, and achievable economic potential for 2026
through 2045.
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2025 Natural Gas IRP Appendix 184

Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Key Data Sources
AEG used Avista's 2024 Washington Natural Gas Conservation Potential Assessment (CPA) as the
foundation for this assessment. The Washington CPA assessed natural gas energy efficiency
potential for Avista's residential, commercial, and industrial sales customers, but excluded
transportation customers. Key updates AEG made to Washington CPA assumptions to reflect
Washington and Oregon transportation customers, loads, and potential included:
Input and market characterization data for this analysis were specific to Avista's Washington and
Oregon transportation customers, including baseline sales, forecasts, and industry
designations.The Washington CPA generally formed the basis for the measure cost assumptions
and savings percentage estimates.
AEG benchmarked the distribution of end use loads with data from the EIA's Commercial Building
and Manufacturing Energy Consumption Surveys and discussed notable differences with Avista
to ensure that they accurately reflected known aspects of those customers. For example, if a
particular manufacturing sector showed a greater proportion of space heating load than
expected compared to MECS data, Avista could confirm that their Oregon transportation
customers was dominated by a facility with significant conditioned space and whose product
line did not require as much natural gas use.
The assessment leveraged the Washington CPA measure list.
Where data gaps existed in Avista data, AEG relied on national and regional data sources for
assumptions in the potential model. Error! Reference source not found. summarizes key data
sources used for the analysis and how each informed the study.
Table 8-3 Key Data Source Summary
Data Source
Load segmentation by industry/building type, presence of
Avista Utility Data equipment,end use load distribution,comparison baseline
forecast,economics inputs,scenario development
Northwest Power and Conservation Technical Achievable ramp rate library and study methodology
Council's 2021 Power Plan
NEEA's 2019 and 2014 Commercial Benchmark equipment saturations,normalized end use and
Building Stock Assessment(CBSA) equipment intensity(therms per sq.ft)
EIA 2018 Manufacturing Energy
Consumption Survey(MECS) and 2018 Estimated equipment use per unit,end use distribution of natural
gas use by business/industry type, benchmarking equipment
Commercial Building Energy
Consumption Survey(CBECS) presence(saturation)
EIA's 2023 Annual Energy Outlook Reference baseline purchase assumptions,equipment lifetimes and
costs
Potential Results
AEG developed achievable economic potential based on assumptions regarding the rate at which
potential could be acquired. The achievable economic potential started with standard ramp rate
assumptions from the Northwest Power and Conservation Council's (Council's) 2021 Power Plan,
mapped to natural gas measures.'
'The Council's 2021 Power Plan only covers electric measures.To adapt these ramp rates for this natural gas
assessment, AEG mapped gas measures to the same or similar electric measure, consistent with the
methodology from the Washington Natural Gas CPA.
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2025 Natural Gas IRP Appendix 185

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Error! Reference source not found. presents the annual potential savings relative to the baseline
projection. Based on the ramp rates used, a majority of the identified potential is assumed to be
acquired over the first 10 years of the study period.
Figure B- 1 Reference Case Cumulative Potential,Washington
25.0%
■Achievable Economic Potential
20.0% ■Achievable Technical Potential
■Technical Potential
aD
15.0%
6
m
m_
° 10.0%
0
5.0%
0.0%
2026 2027 2030 2035 2045
Figure B- 2 Reference Case Cumulative Potential,Oregon
25.0%
■Achievable Economic Potential
20.0% ■Achievable Technical Potential
■Technical Potential
a�
15.0%
CU
m
m_
0 10.0%
0
5.0%
Id 1
0.0%
2026 2027 2030 2035 2045
Commercial Potential Results
Figure A-3 Achievable Economic Potential, 2045
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2025 Natural Gas IRP Appendix 186

Avista Natural Gas Conservation PotentialAssessment for 2026-2045
Potential by Market Segment
Mobile
Home
10%
FMulti-Famil',,
presents the percentage of achievable economic
potential in 2045 by market segment and end use. Single family dwellings account for 73% of low-
income achievable economic potential. Space heating accounts for 76%of low-income achievable
economic potential.
Figure A-3 Achievable Economic Potential,2045
Potential by Market Segment
Mobile
Home
10%
31
and Error! Reference source not found. present
the percentage of achievable economic potential 2045 by market segment and end use,
respectively. The majority of Avista's commercial transportation customers are Health (71% in
Oregon) and College (69% in Washington). Space heating accounts for the largest share of end use
potential in both states, representing 51%and 70%of cumulative commercial achievable economic
potential in Oregon and Washington, respectively.
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2025 Natural Gas IRP Appendix 187

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 8-3 Commercial Achievable Economic Potential by Market Segment,2045
Oregon Washington
Miscellaneous Miscellaneous
3% 14%
Heallth
College
69%
Figure 8-4 Commercial Achievable Economic Potential by End Use,2045
Oregon Washington Food
Food rPreparation
Preparation / 9%
24%
Water
Water
Heating Heating
21% FF
25%
SpaceFF
..
ce
Heating Heating
1'
Cumulative commercial achievable economic potential is provided in Figure A- presents a forecast
of cumulative achievable economic potential by end use. Space heating accounts for the majority of
potential but declines slightly in the mid-2020s due to a future furnace standard.
Figure A-for Oregon and Figure B-for Washington.
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2025 Natural Gas IRP Appendix 188

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 8-5 Cumulative Achievable Economic Commercial Potential by End Use, Oregon
30,000
25,000
20,000 ■Space Heating
t ■Water Heating
15,000
■Food Preparation
10,000 ■Miscellaneous
5,000
un lD r` 00 m O -1 N CO 'zZr in tD r` 00 M O -1 N M �T in
N N N N N M M M M M M M co M M V �T `TK� zT -zt
O O O O O O O O O O O O O O O O O O O O O
N N N ('4 N N N N N N N N N N N N N N N N N
Figure 8-6 Cumulative Achievable Economic Commercial Potential by End Use, Washington
180,000
160,000
140,000
120,000 ■Space Heating
y 100,000 ■Water Heating
0
80,000 ■Food Preparation
60,000 ■Miscellaneous
40,000
20,000
u1 lD r, 00 M O c-I N M zt Ln l0 r, 00 0) O -1 N M qT Ln
N N N N N M M CO M M M CO CO M CO V � ':T �* KT -zt
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
Industrial Potential Results
Figure B-presents the cumulative industrial potential in 2045 by end use. Industrial process end use
accounts for 94%of Oregon's identified industrial achievable economic potential process and 92%
of Washington's identified industrial achievable economic potential.
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2025 Natural Gas IRP Appendix 189

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 8-7 Industrial Achievable Economic Potential by End Use,2045
Oregon Washington
Space Space
Heath Heating
8% \ 6%
Process Process
92% 94%
Cumulative industrial achievable economic potential is provided in Figure B-for Oregon and Figure
B-for Washington.
Figure 8-8 Cumulative Achievable Economic Industrial Potential by End Use, Oregon
250,000
200,000
■Space Heating
t
150,000 Secondary Heating
o ■Water Heating
■Appliances
100,000 ■Food Preparation
■Process
50,000 ■Miscellaneous
Ln lD r, 00 M O -1 N CO 'zZr Ln LD r\ 00 M O ci N M V M
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
Applied Energy Group,Inc.,proudly part of ICF 94 of 105
2025 Natural Gas IRP Appendix 190

Avista Natural Gas Conservation Potential Assessment for 2026-2045
Figure 8-9 Cumulative Achievable Economic Industrial Potential by End Use, Washington
200,000
180,000
160,000
140,000 ■Space Heating
t
120,000 Secondary Heating
o ■Water Heating
100,000
■Appliances
80,000 ■Food Preparation
60,000 ■Process
40,000 ■Miscellaneous
20,000
ui �D r` oo m o -1 N CO 'zZr in �D r` oo m o -1 N M KT in
N N N " N M ro M M m m ro CO m ro V -t a a �t �
O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N
Considerations and Recommendations
This assessment was a first step in identifying and realizing natural gas energy efficiency (and
associated greenhouse gas emissions reductions) within Avista's transportation customer base.
While program design is outside the scope of this assessment, AEG notes the following items for
Avista as it determines the best way to achieve these savings:
Many of the inputs into the analysis are averages across market segments based on the best
available data sources and may not reflect the available potential at any individual site. To
address this, AEG recommends that Avista consider sponsoring audits of specific
transportation customer sites to better understand current equipment and practices to
refine estimates of available potential for these customers.
Because a small number of customers account for a large amount of transportation customer
consumption, whether these customers choose to participate in future programs will
significantly affect the amount of savings that Avista is able to achieve. This uncertainty could
increase or decrease acquisition levels relative to the potential identified in this assessment. As
Avista considers new program designs for transportation customers, AEG recommends
targeted outreach to the largest customers to understand their likelihood of participating in
future programs, including to what extent and on what timeline.
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2025 Natural Gas IRP Appendix 191

Avista Natural Gas Conservation Potential Assessment for 2026-2045
C I MARKET PROFILES
This appendix presents the market profiles for each sector and segment for Washington and Idaho,
in the embedded spreadsheet.
1
Avista 2024-Natural
Gas Market Profiles.xl
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2025 Natural Gas IRP Appendix 192

Avista Natural Gas Conservation Potential Assessment for 2026-2045
D I MARKET ADOPTION (RAMP) Rates
This appendix presents the Power Council's 2021 Power Plan ramp rates we applied to technical potential to estimate Technical Achievable
Potential.
Table 8- 1 Measure Ramp Rates Used in CPA
L012Med 11% 22% 33% 44% 55% 65% 72% 79% 84% 88% 91% 94% 96% 97% 99% 100% 100% 100% 100% 100%
L05Med 4% 10% 16% 24% 32% 42% 53% 64% 75% 84% 91% 96% 99% 100% 100% 100% 100% 100% 100% 100%
L01Slow 1% 1% 2% 3% 5% 9% 13% 19% 26% 34% 43% 53% 63% 72% 81% 87% 92% 96% 98% 100%
L050Fast 45% 66% 80% 89% 95% 98% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
L020Fast 22% 38% 48% 57% 64% 70% 76% 80% 84% 88% 90% 92% 94% 95% 96% 97% 98% 98% 99% 100%
LOEven20 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%
L03Slow 1% 1% 3% 6% 11% 18% 26% 36% 46% 57% 67% 76% 83% 88% 92% 95% 97% 98% 99% 100%
L080Fast 76% 83% 88% 92% 95% 97% 98% 99% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Retro12Med 11% 11% 11% 11% 11% 10% 8% 6% 5% 4% 3% 3% 2% 2% 1% 1% 0% 0% 0% 0%
Retro5Med 4% 5% 6% 8% 9% 10% 11% 11% 11% 9% 7% 5% 3% 1% 1% 0% 0% 0% 0% 0%
Retro1Slow 0% 1% 1% 1% 2% 3% 4% 6% 7% 8% 9% 10% 10% 9% 8% 7% 5% 4% 2% 2%
Retro50Fast 45% 21% 14% 9% 6% 3% 1% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Retro20Fast 22% 16% 11% 8% 7% 6% 5% 5% 4% 3% 3% 2% 2% 1% 1% 1% 1% 1% 1% 0%
RetroEven20 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5%
Retro3Slow 1% 1% 2% 3% 5% 7% 8% 10% 11% 11% 10% 9% 7% 6% 4% 3% 2% 1% 1% 1%
97 of 105
2025 Natural Gas IRP Appendix 193

E I Measure Data
Measure level assumptions and data are available in the"Avista 2024 DSM Potential Study Measure
Assumptions"workbook provided to Avista alongside this file.
10�
Avista 2024 DSM
Natural Gas CPA Mea
Applied Energy Group•www.appLiedenergygroup.com 98 of 105
2025 Natural Gas IRP Appendix 194

J7-
Applied Energy Group, Inc.
2300 Clayton Road
Suite 1370
Concord, CA 94520
P: 510-982-3526
2025 Natural Gas IRP Appendix 195

Energy Trust of Oregon Background
Energy Trust of Oregon, Inc. (Energy Trust) is an independent nonprofit organization dedicated
to helping investor-owned utility customers in Oregon and southwest Washington benefit from
saving energy and generating renewable power. Energy Trust funding comes from utility
customers and is invested on their behalf in lowest-cost energy efficiency and clean, renewable
energy. In 1999, Oregon energy restructuring legislation (SB 1149) required Oregon's two
largest electric utilities—Portland General Electric and Pacific Power—to collect a public
purpose charge from their customers to support energy conservation in K-12 schools, low-
income housing energy assistance, and energy efficiency and renewable energy programs for
residential and business customers.
In 2001, Energy Trust entered into a grant agreement with the Oregon Public Utility Commission
(OPUC) to invest the majority of revenue from the 3 percent public purpose charge in energy
efficiency and renewable energy programs'. Every dollar invested in energy efficiency by
Energy Trust will save residential, commercial, and industrial customers nearly $3 in deferred
utility investment in generation, transmission, fuel purchase and other costs. Appreciating these
benefits, natural gas companies asked Energy Trust to provide service to their customers—NW
Natural in 2003, Cascade Natural Gas in 2006 and Avista in 2017. These arrangements
stemmed from settlement agreements reached in Oregon Public Utility Commission processes.
Energy Trust's model of delivering energy efficiency programs as a single entity across the five
overlapping service territories of Oregon's investor-owned gas and electric utilities has
experienced a great deal of success. Since its inception, Energy Trust has saved more than 965
aMW of electricity and 100 million annual therms. This equates to more than 42.9 million metric
tons of CO2 emissions avoided and is a significant factor contributing to the relatively flat energy
sales observed by both gas and electric utilities from 2014 to 2023—with electric sales
decreasing and natural gas sales very slightly increasing—as shown in OPUC utility statistic
books.2
Energy Trust serves residential, commercial, firm, interruptible, and transport industrial
customers in Avista's natural gas service territory in the areas of Medford, Klamath Falls, and La
Grande, Oregon. In 2024, Energy Trust's programs achieved savings of 600,509 therms—
equivalent to about 110% of the IRP target, as shown in
' Energy Trust's funding mechanism was updated in 2021 from HB 3141. See
https://olis.oregonIegislature.gov/liz/2021R1/Downloads/PublicTestimonyDocument/5138 for more information.
z OPUC 2023 Stat book—10 Year Summary Tables:
https://www.oregon.gov/puc/forms/Forms%20and%2OReports/2023-Oregon-Utility-Statistics-Book.pdf
2025 Natural Gas IRP Appendix 196

Figure 1. As seen in the figure, 2021 is the first year Energy Trust savings in Avista's Oregon
service territory are below the IRP target. While savings remained relatively consistent with
2020, Energy Trust projected growth in 2021 as an extension of increased efficiency activities
seen in 2020 as a result of pandemic related market conditions. However, supply chain and
labor difficulties experienced in 2021 slowed down the rate of growth Energy Trust was able to
achieve. This gap widened in 2022 and nearly closed in 2023. Energy Trust is working with
Avista to further develop program delivery infrastructure to accelerate savings acquisition to
meet carbon reduction requirements in context with related least-cost planning principles.
2025 Natural Gas IRP Appendix 197

Figure 1 —Achieved Savings by Sector vs. IRP Targets for Avista Service Territory
0.70
0.60
0.50
E 0.40
0.30
0.20
0.10
0.00
2019 2020 2021 2022 2023 2024
�Residential Commercial Industrial IRP Target
In addition to administering energy efficiency programs on behalf of the utilities, Energy Trust
also provides each utility with a 20-year forecast of cost-effective energy efficiency savings
potential expected to be achieved by Energy Trust. The results are used by Avista and other
utilities in Integrated Resource Plans (IRP) to inform the energy efficiency resource potential in
their territory that can be used in their resource mix to meet their customers' projected load.
Energy Trust 20-Year Forecast Methodology
20-Year Forecast Overview
Energy Trust developed a DSM resource forecast for Avista using its resource assessment
modeling tool (hereinafter the "RA Model") to identify the total 20-year cost-effective modeled
savings potential. This potential is subsequently `deployed' exogenously of the model to
estimate the final savings forecast for each of the 20 years. There are four types of potential that
are calculated to develop the final savings potential estimate. These are shown in
Figure 2 and discussed in greater detail in the sections below.
Figure 2 —Types of Potential Calculated in 20-year Forecast Determination
Technical Potential
Not Calculated
Technically within RA
Feasible Market Model
Barriers Achievable Potential
2025 Natural Gas IRP Appendix 198

Cost-Effective Achievable
Potential
Not Developed
Effective Program Final Program with
Design & Savings Programs &
Market Potential Other
Penetration Market
Information
The RA Model utilizes the modeling platform Analytica®3, an object-flow based modeling
platform that is designed to visually show how different objects and parts of the model
interrelate and flow throughout the modeling process. The model utilizes multidimensional
tables and arrays to compute large, complex datasets in a relatively simple user interface.
Energy Trust then deploys this cost-effective potential exogenously to the RA model into an
annual savings projection based on past program experience, knowledge of current and
developing markets, and future codes and standards. This final 20-year savings projection is
provided to Avista for inclusion in in their CROME Model as a reduction to demand on the
system.
20-Year Forecast Detailed Methodology
Energy Trust's 20-year forecast for DSM savings follows six overarching steps from initial
calculations to deployed savings, as shown in
3 http://www.lumina.com/why-analytica/what-is-analytical/
2025 Natural Gas IRP Appendix 199

Figure 3. The first five steps in the varying shades of blue nodes - Data Collection and Measure
Characterization to Cost-Effective Achievable Energy Efficiency Potential- are calculated within
Energy Trust's RA Model. This results in the total cost-effective potential that is achievable over
the 20-year forecast. The actual deployment of these savings (the acquisition percentage of the
total potential each year, represented in the green node of the flow chart) is done exogenously
of the RA model. The remainder of this section provides further detail on each of the steps
shown below.
2025 Natural Gas IRP Appendix 200

Figure 3 - Energy Trust's 20-Year DSM Forecast Determination Flow Chart
Measure Level Inputs itility'Global Inputs'
arearrand \IJrletDra Load t btomer Gstanri ttYAWld•O
M•as.re IntrOtttental i.Ynsry/X]t..YQfu Fgretaatf tiOJnti/ XOc► -tIWrherm
CQJQflMnt Swln� COGK /SutQA1 r/ hY Sf[[nf OJIIdif�XOtl.[ 0•rnogapNti SiV•Ql
Technical zy Efficiency Potential
availableAll technically potential in service territory
Cost-Effectiveness Screen
Measures arc screened for cosh using the TRC Test
TodW Resixurm Cost Test fW=&new/Costs
Cost-Effective Achievable Energy Efficiency Potential
Measures with TRC Ratio>1.0 included in Cost-Effective Achievable Potential
Deployment of Cost-Effective Achievable EE Potential
Exogenous of the RA Model-Energy Trust works internally with programs and uses
NWPPC council methodologies to determine acquisition rates of CE Potential
1. Data Collection and Measure Characterization
The first step of the modeling process is to identify and characterize a list of measures to
include in the model, as well as receive and format utility `global' inputs for use in the model.
Energy Trust compiles and loads a list of commercially available and emerging technology
measures for residential, commercial, industrial, and agricultural applications installed in
new or existing structures. The list of measures is meant to reflect the full suite of measures
offered by Energy Trust, plus a spectrum of emerging technologies.4 In addition to
identifying and characterizing applicable measures, Energy Trust collects necessary data to
scale the measure level savings to a given service territory (known as `global inputs').
• Measure Level Inputs:
Once the measures have been identified for inclusion in the model, they must be
characterized in order to determine their savings potential and cost-effectiveness.
The characterization inputs are determined through a combination of Energy Trust
a An emerging technology is defined as technology that is not yet commercially available but is in some stage of
development with a reasonable chance of becoming commercially available within a 20-year timeframe. The model
is capable of quantifying costs,potential,and risks associated with uncertain,but high-saving emerging technology
measures. The savings from emerging technology measures are reduced by a risk-adjustment factor based on what
stage of development the technology is in. The working concept is that the incremental risk-adjusted savings from
emerging technology measures will result in a reasonable amount of savings over standard measures for those few
technologies that eventually come to market without having to try and pick winners and losers.
2025 Natural Gas IRP Appendix 201

primary data analysis, regional secondary sources5, and engineering analysis. There
are over 30 measure level inputs that feed into the model, but on a high level, the
inputs are organized into the following categories:
1. Measure Definition and Equipment Identification: This is the definition of
the efficient equipment and the baseline equipment it is replacing (e.g., wall
insulation greater than or equal to R11 replacing wall insulation with an R
value of four or less). A measure's replacement type is also determined in
this step — retrofit, replace on burnout, or new construction.
2. Measure Savings: natural gas savings associated with an efficient measure
calculated by comparing the baseline and efficient measure consumptions.
3. Incremental Costs: The incremental cost of an efficient measure over the
baseline. The definition of incremental cost depends upon the replacement
type of the measure. If a measure is a retrofit measure, the incremental cost
of a measure is the full cost of the equipment and installation. If the measure
is a replace on burnout or new construction measure, the incremental cost of
the measure is the difference between the cost of the efficient measure and
the cost of the baseline equipment.
4. Market Data: Market data of a measure includes the density, saturation, and
suitability of a measure. The density is the number of measure units that can
be installed per scaling basis (e.g., the average number of showers per home
for showerhead measures). Saturation is the share of equipment that is
already efficient (e.g., 50% of the showers already have a low flow
showerhead). Suitability of a measure is a percentage that represents the
percent of installation opportunities where the measure can actually be
installed. These data inputs are generally derived from regional market data
sources such as NEEA's Residential and Commercial Building Stock
Assessments.
• Utility Global Inputs:
The RA Model requires several utility-level inputs to create the DSM forecast.
These inputs include:
1. Customer and Load Forecasts:These inputs are essential to scale the
measure level savings to a utility service territory. For example,
residential measures are characterized on a `per home' scaling basis, so
the measure densities are calculated as the number of measures per
home. The model then takes the number of homes that Avista has
forecasted to scale the measure level potential to their entire service
territory.
2. Customer Stock Demographics:These data points are utility specific
and identify the percentage of customer building stock that utilize different
fuels for space and water heating. The RA Model uses these inputs to
segment the total stock to the portion that is applicable to a measure
(e.g., gas water heaters are only applicable to customers that have gas
water heat).
3. Utility Avoided Costs:Avoided costs are the net present value of
avoided energy purchases and delivery costs associated with energy
savings. Energy Trust calculates these values based on inputs provided
by Avista. The avoided cost components are discussed in other sections
s Secondary Regional Data sources include: The Northwest Power Planning Council(NWPPC),the Regional
Technical Forum(the technical arm of the NWPPC),and market reports such as NEEA's Residential and
Commercial Building Stock Assessments(RBSA and CBSA).
2025 Natural Gas IRP Appendix 202

of this IRP. Avoided costs are the primary benefit of energy efficiency in
the cost-effectiveness screen.
2. Calculate Technical Energy Efficiency Potential
Once measures have been characterized and utility data loaded into the model, the next
step is to determine the technical potential of energy that could be saved. Technical
potential is defined as the total energy savings potential of a measure that could be
achieved regardless of cost or market barriers, representing the maximum potential energy
savings available. The model calculates technical potential by multiplying the number of
applicable units of a measure in the service territory by the measure's savings. The model
determines the total number of applicable units for a measure utilizing several of the
measure level and utility inputs referenced above:
Total applicable units= Measure Density*Baseline Saturation *Suitability Factor*Heat Fuel
Multipliers(if applicable) *Total Utility Stock(e.g., #of homes)
Technical Potential= Total Applicable Units *Measure Savings
This savings potential does not consider the various cost and market barriers that will limit
the adoption of efficiency measures.
3. Calculate Achievable Energy Efficiency Potential
Achievable potential is simply a reduction of the technical potential to account for market
barriers that prevent the adoption of the measures identified in the technical potential. This
is done by applying a factor to reflect the maximum achievability for each measure. Energy
Trust first updated its methodology in Avista's 2020 IRP to reflect the maximum achievability
estimated by the Northwest Power and Conservation Council for the 2021 Power Plan, and
has done so again for the 2025 IRP. While in past power plans a universal assumption of
85% was used, these factors now typically range from 85% to 95%.6
Achievable Potential= Technical Potential*Maximum Achievability Factor
4. Determine Cost-effectiveness of Measure using TRC Screen
The RA Model screens all DSM measures in every year of the forecast horizon using the
Total Resource Cost (TRC) test. This test evaluates the total present value of all benefits
attributable to the measure divided by the total present value of all costs. A TRC test value
greater than or equal to 1.0 means the value of benefits is equal to or exceeds the costs and
the measure is cost-effective and contributes to the total amount of cost-effective potential.
The TRC is expressed formulaically as follows:
TRC = Present Value of Benefits/Present Value of Costs
Where the Present Value of Benefits includes the sum of the following two components:
a) Avoided Costs: The present value of natural gas energy saved over the life of the
measure, as determined by the total therms saved multiplied by Avista's avoided
cost per therm. The net present-value of these benefits is calculated based on
the measure's expected Iifespan using the company's discount rate.
6 For details on this, see https://www.nwcouncil.org/sites/default/files/2019_08l3—p5.pdf.
2025 Natural Gas IRP Appendix 203

b) Non-energy benefits are also included when present and quantifiable by a
reasonable and practical method (e.g., water savings from low-flow showerheads
or operations and maintenance cost reductions from advanced controls).
Where the Present Value of Costs includes:
a) Incentives paid to the participant; and
b) The participant's remaining out-of-pocket costs for the installed cost of the
measures after incentives, minus state and federal tax credits.
The cost-effectiveness screen is a critical component for Energy Trust modeling and
program planning because Energy Trust is only allowed to incentivize cost-effective
measures unless an exception has been granted by the OPUC.
5. Quantify the Cost-Effective Achievable Energy Efficiency Potential
The RA Model's final output of potential is the quantified cost-effective achievable potential.
If a measure passes the TRC test described above, then the achievable savings from a
measure is included in this potential. If the measure does not pass the TRC test above, the
measure's potential is not included in cost-effective achievable potential. However, the cost-
effectiveness screen is overridden for some measures under two specific conditions:
1) The OPUC has granted an exception to offer non-cost-effective measures under
strict conditions or,
2) When the measure is not cost-effective using utility-specific avoided costs, but the
measure is cost-effective when using blended gas avoided costs for all of the gas
utilities Energy Trust serves and is therefore offered by Energy Trust programs.
6. Deployment of Cost-Effective Achievable Energy Efficiency Potential
After determining the 20-year cost-effective achievable modeled potential, Energy Trust
develops a savings projection based on past program experience, knowledge of current and
developing markets, and future codes and standards. The savings projection is a 20-year
forecast of energy savings that will result in a reduction of load on Avista's system. This
savings forecast includes savings from program activity for existing measures and emerging
technologies, expected savings from market transformation efforts that drive improvements
in codes and standards, and a forecast of savings from very large projects that are not
characterized in Energy Trust's RA Model but consistently appear in Energy Trust's historic
savings record and have been a source of overachievement against IRP targets in prior
years for other utilities that Energy Trust serves.
2025 Natural Gas IRP Appendix 204

Figure 4 below reiterates the types of potential shown in
Figure 2, and how the steps described above and in the flow chart fit together.
2025 Natural Gas IRP Appendix 205

Figure 4 -The Progression to Program Savings Projections
Data Collection and Measure Characterization Step 1
Technical Potential Step 2
Achievable Potential Step 3
Not
Technically
Feasible Market Cost-Effective Achievable Steps 4 & 5
Barriers Potential
Not Cost- Program
Effective Design & Final Program
Market Savings Step 6
Penetration Potential
Forecast Results (Base Case)
The results of Energy Trust's forecast are shown below.
RA Model Results — Technical, Achievable and Cost-Effective Achievable
Potential
The RA Model produces results by potential type, as well as several other useful outputs,
including a supply curve based on the levelized cost of energy efficiency measures. This section
discusses the overall model results by potential type and provides an overview of the supply
curve. These results do not include the application of ramp rates applied in Step 6 described
above.
Forecasted Savings by Sector
Table 1 summarizes the technical, achievable, and cost-effective potential for Avista's system in
Oregon. These savings represent the total 20-year cumulative savings potential identified in the
RA Model by the three types identified in
2025 Natural Gas IRP Appendix 206

Figure 4 above. Modeled savings represent the full spectrum of potential identified in Energy
Trust's resource assessment model through time, prior to deployment of these savings into the
final annual savings projection.
Table 1 -Summary of Draft Total First-Year Modeled Savings Potential —2025-2044
Technical Potential Achievable Potential i Cost-Effective
(Million Therms) (Million Therms) Achievable Potential
(Million Therms)
Residential? 15.2 13.4 12.8
Commercial 6.6 5.6 5.5
Industrial 0.7 0.6 0.5
Total 22.5 19.6 18.8
Figure 5 shows total first-year forecasted savings potential across the three sectors Energy
Trust serves, as well as the type of potential identified in Avista's service territory. Residential
sales make up the majority of Avista's service in Oregon, which is reflected in the potential.
Industrial sales represent a small percentage of the total sales in Oregon for Avista, and
subsequently shows little savings potential. 80% of the industrial technical potential is cost-
effective, while in the residential and commercial sectors, cost-effective achievable potential is
84% and 83% of technical potential, respectively.
Figure 5—Total First-Year Savings Potential by Sector and Type 2025-2044 (Millions of Therms)
16
14
12
E 10
^L'
W
8 v
6
4
2
0
Residential Commercial Industrial
■Technical Achievable Cost-effective achievable
Cost-Effective Achievable Savings by End-Use
7 Residential sector savings potential reflect the load and stock forecast from Avista's residential customers in
Oregon, excluding low-income customers modeled separately by AEG.
2025 Natural Gas IRP Appendix 207

Figure 6 below provides a breakdown of Avista's 20-year total first-year savings potential by end
use.
2025 Natural Gas IRP Appendix 208

Figure 6—20-year Total First-Year Savings Potential by End Use
7
6 —
U)
5
E
� 4
~ 3
2
1
0 1 ■ _ _
.�°� ��o, �o, °� .���o, c°ooQ, ��o' JQG
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Q
■Technical Achievable Cost-effective achievable
As is typical for a gas utility, the top saving end uses are weatherization, heating, and water
heating. A large portion of the water heating end-use is attributable to new construction homes
due to how Energy Trust assigns end uses to the New Homes pathways offered through Energy
Trust's residential programs. The New Home pathways are packages of measures in new
construction homes with savings that span several end-uses. Energy Trust assigns an end-use
to each of the New Homes pathways based on the end-use that achieves the most significant
savings in the package. For example, the most cost-effective New Home pathway that was
identified by the model (because it achieves the most savings for the least cost) was designated
as a water heating end-use, though the package includes several other efficient gas equipment
measures.
In addition to the New Homes pathway savings, the water heating end-use includes water
heating equipment from all sectors. The behavioral end use consists primarily of potential from
Energy Trust's commercial strategic energy management measure, a service where Energy
Trust energy experts provide training and support to facilities teams and staff to identify
operations and maintenance changes that make a difference in a building's energy use.
Contribution of Emerging Technologies
As mentioned earlier in this report, Energy Trust includes a suite of emerging technologies in its
model. The emerging technologies included in the model are listed in Table 2.
Table 2 - Emerging Technologies Included in the Model
Resident i Industrial
2025 Natural Gas IRP Appendix 209

• Attic Insulation R-60 0 Condensing Gas Rooftop Unit 0 Advanced Wall
• Cellular Shades 0 Gas Absorption Heat Pump Hot Insulation
• Gas Absorption Heat Pump Water 0 Gas-Fired Heat
Water Heater 0 Gas-Fired Heat Pump Pump Water
• Gas-Fired Heat Pump 0 Gas RTU Advanced Tier 1 Heater
• Thin Triple Pane Windows 0 Thin Triple Pane Windows
• Wall Insulation R-30 0 Zero Net Energy
Energy Trust recognizes that emerging technologies are inherently uncertain and applies a risk
factor to hedge against that uncertainty. The risk factor for each emerging technology is used to
characterize the inherent uncertainty in the ability for emerging technologies to produce reliable
future savings. This risk factor is determined based on qualitative risk categories, including:
• Market risk
• Technical risk
• Data source risk
The framework for assigning the risk factor is shown in Table 3. Each emerging technology was
assessed within each risk category and then a total weighted score was then calculated. Well-
established and well-studied technologies have lower risk factors and nascent, unevaluated
technologies have higher risk factors. This risk factor is then applied as a multiplier to reduce
the incremental savings potential of the measure.
2025 Natural Gas IRP Appendix 210

Table 3 - Emerging Technology Risk Factor Score Card
Emerging Technology Risk Factor
Risk 10% 30% 50% 70% 90%
Category
Market High Risk: Low Risk:
Risk Trained contractors
Requires new/changed business
(25% model Established business models
weighting) Already in U.S. Market
Start-up,or small manufacturer
• Significant changes to infrastructure Manufacturer committed to
commercialization
• Requires training of contractors.
Consumer acceptance barriers
exist.
Technical High Risk: Low volume New product with Proven technology Low Risk:
Risk Prototype in first manufacturer. broad commercial in different Proven
(25% field tests. Limited experience appeal application or technology in
weighting) A single or different region target
unknown application.
approach Multiple
potentially
viable
a roaches.
Data High Risk: Based Manufacturer case Engineering Third party case Low Risk:
Source only on studies assessment or lab study(real world Evaluation
Risk manufacturer test installation) results or
(50% claims multiple third-
weighting) party case
studies
Figure 7 below shows the amount of emerging technology savings within each type of potential.
While emerging technologies make up a reasonable percentage of the technical and achievable
potential, between 15% and 16%, once the cost-effectiveness screen is applied, the relative
share of emerging technologies drops to 11% of total cost-effective achievable potential. This is
because some of these technologies are still in early stages of development and are quite
expensive. Though Energy Trust includes factors to account for forecasted decreases in cost
and increased savings from these technologies over time where applicable, some are not cost-
effective at any point over the planning horizon.
Figure 7—Total First-Year Savings Contribution of Emerging Technologies by Potential Type
25
20 15.5%
11.4%
U)
E 15
m
I-
10
5
0
Technical Achievable Cost-Effective Achievable
■Conventional Emerging
2025 Natural Gas IRP Appendix 211

Cost-Effective Override Effect
Table 4 shows the savings potential in the RA model that was added by employing the cost-
effectiveness override option in the model. As discussed in the methodology section, the cost-
effectiveness override option forces non-cost-effective potential into the cost-effective potential
results and is used when a measure meets one of the following two criteria:
1. A measure is offered under an OPUC exception.
2. When the measure is not cost-effective using Avista-specific avoided costs, but the
measure is cost-effective when using blended gas avoided costs for all of the gas utilities
Energy Trust serves and is therefore offered by Energy Trust programs.
Table 4—Total First-Year Cost-Effective Savings Potential (2025-2044) due to Cost-Effectiveness
Exception (Millions of Therms)
Sector Effectiveness Effectiveness Difference
With Cost Without Cost
Residential 12.8 12.3 (0.5)
Commercial 5.5 5.5 -
Industrial 0.5 0.5 -
Total 18.8 18.2 (0.5)8
In this IRP, approximately 3% of the cost-effective potential identified by the model is due to the
use of the cost-effective override. The measures that had this option applied to them included
residential attic, floor, and wall insulation, windows and storm windows, multifamily windows,
gas heated new manufactured homes, clothes washers, and market solutions whole-home
building tracks.
Supply Curves and Levelized Cost Outputs
An additional output of the RA Model is a resource supply curve developed from the levelized
cost of energy of each measure. The supply curve graphically depicts the total potential that
could be saved at various costs. The Ievelized cost provides a consistent basis for comparing
efficiency measures and other resources with different lifetimes. The Ievelized cost calculation
starts with the incremental cost of a given measure. The total cost is amortized over the
estimated measure lifetime using Avista's discount rate. The annualized measure cost is then
divided by the annual natural gas savings. Some measures have negative Ievelized costs
because these measures have non-energy benefits that are greater than the total cost of the
measure over the same period.
Figure 8 below shows the supply curve developed for this IRP that can be used for comparing
demand-side and supply-side resources. The cost-effective potential, without override,
identified in this assessment is approximately 18.2 million therms, which translates to
approximately $3.86/therm on this graph. This is not a precise point, however, since measures
around this point will save natural gas at different times in relation to Avista's peak periods and
therefore have varying capacity values that function to make them more or less cost-effective.
Consequently, measures on either side of this point may or may not be cost effective. Finally,
after approximately $3/therm, additional potential comes at rapidly increasing cost increments.
s Difference column may not exactly equal the difference between the two values of potential with and without the
cost-effectiveness exception due to rounding.
2025 Natural Gas IRP Appendix 212

Figure 8— Natural Gas Efficiency Supply Curve
20
E 15
a�
c 10
a�
0
a
a�
ca
E 5
0
U
-$5 -$3 -$1 $1 $3 $5 $7 $9
Levelized Cost($/therm)
Deployed Results — Final Savings Projection
The results of the final savings projection show that Energy Trust can achieve 3.2 million annual
therm savings across Avista's system in Oregon from 2025 to 2030 and 13.9 million therms by
the end of 2044. This represents an 18.4 percent cumulative load reduction by 2044 and is an
average of a 0.9 percent incremental annual load reduction. The cumulative final savings
projection is shown in Table 5, which shows the technical, achievable, and cost-effective
achievable potential for comparison.
Table 5 - 20-Year Total First-Year Savings Potential by Type (Millions of Therms)
Cost- Energy Trust
Technical Achievable Effective Deployed Savings
Potential Potential Achievable Projection
Potential
Residential 15.2 13.4 12.8 8.5
Commercial 6.6 5.6 5.5 3.7
Industrial 0.7 0.6 0.5 0.5
Exogenous' - - - 1.2
Total 22.5 19.6 18.8 13.9
9 The final deployed savings projection includes savings calculated outside of the modeling process consisting of the
large project adder and unclaimed market savings.
2025 Natural Gas IRP Appendix 213

The final deployed savings projection is less than the modeled cost-effective achievable
potential. The primary reason for this additional step down in savings is lost opportunity
measures. These measures are meant to replace failed equipment or be installed in new
construction. They are considered lost opportunity measures because programs have one
opportunity to influence the installation of efficient equipment when the existing equipment fails
or when the new building is built. This is because these measures must be installed at that
specific point in time, and if the efficient equipment is not installed, then the opportunity is lost
until the equipment fails again. Energy Trust assumes that most lost opportunity measures have
gradually increasing annual adoption rates as time passes due to increasing program influence
and increasing codes and standards. In addition to lost opportunities, some retrofit measures
(notably insulation and windows) face market barriers that inhibit them from achieving full
market penetration by the end of the time period.
Figure 9 below shows the annual savings projection by sector. Savings totals in years 2025
through 2030 reflect Energy Trust's multiyear planning and strategic plan, while in 2031 and
beyond NWPCC ramp rates take over. Savings growth throughout the forecast horizon is
expected to be fairly consistent.
Figure 9—Annual Deployed Final Savings Potential by Sector
1.0
0.9
0.8 — —
0.7
E 0.6
0.5
0.4
0.3
0.2
00.1
.0 I11 III
O`Llb O`L10 O`A O�b O�1 O1Z O51 O1� O1� O`4x O19 O4) O�� O1b O�, O�� O�� O0 O0 O��
ti � 1 ti 1 ti ti 1 � � ti ti ti 1 � 1 ti ti
■Commercial Residential Industrial ■Large Project Adder ■Unclaimed Market Savings
Finally, Figure 10 shows the annual and cumulative savings as a percentage of Avista's load
forecast in Oregon. Annually, the savings as a percentage of load varies from about 0.6% at its
lowest to 1.1% at its highest, as represented on the left axis and the blue line. Cumulatively, the
savings as a percentage of load builds to 18.4% by 2044.
2025 Natural Gas IRP Appendix 214

Figure 10—Annual and Cumulated Forecasted Savings as a Percentage of Avista Load Forecast
20%
18%
18%
16%
14%
J 12%
0 10%
a�
L
cu 8%
'�
VJ
6%
4%
2%
0%
10
Annual Share of Load Cumulative Share of Load
Comparison to 2023 IRP Savings Projection
Figure 11 below shows the annual deployed savings potential discussed above compared to
Avista's previous IRP completed in 2023. Near-term savings projections in the 2025 IRP are
lower than in 2023 to reflect updated market conditions and Energy Trust program expectations
from the multiyear planning process. Efficiency potential estimates in the 2025 IRP, and
especially in the residential sector, are sufficient to support steady growth throughout the
forecast horizon. Savings projections in the 2023 IRP peak in 2034 and then decline as market
potential in the industrial and commercial sectors become exhausted. The combination of a
lower savings starting point and a more linear growth rate leave enough market potential to
support growth throughout the forecast period. For context, the 2025 IRP achieves 62% of
technical potential while the 2023 forecast captured 55% as shown in table 6 below.
2025 Natural Gas IRP Appendix 215

Figure 11 —Annual Deployed Final Savings Projection Compared to 2023
1
0.9
0.8 1
0.7
In 0.6
0.5
0.4
0.3 -
0.2
0.1
0
O`l3 O`l'D O`l<0 O`1(b O`A O`1b O�9)OHO O�`y On�`L Onj3 00�O�h O��0�A O��b O�0 OpO Opti O�`1.Op3 OpD
2023 IRP Total 2025 IRP Total
Table 6 below compares the modeled potential between this study and the 2023 IRP. Savings
are down in each category of potential in the 2025 IRP compared to the 2023 IRP, however a
higher share of cost-effective potential is reflected in the final deployment. This is primarily due
to the reduced load and stock forecast in the 2025 IRP compared to the 2023 IRP. The 2025
IRP also has a lower proportion of emerging technology potential. Energy Trust applies a
different ramp rate to emerging technologies than the ramp rate applied to conventional
technologies. The emerging technology ramp rate places emerging technologies at the
beginning of an adoption curve when the model demonstrates that they become market ready
and cost-effective.
Table 6 -20-Year First-Year Savings Potential by IRP Vintage (Millions of Therms)
Technical 27.6 22.4 (5.2)
Achievable 22.3 19.6 (2.7)
Cost- 21.6 18.8 (2.9)
Effective
Deployed 15.4 14.7 (0.7)
Table 7 details the individual changes contributing to the 2.9 MM therm decrease in cost-
effective achievable potential shown above. Changes in load and stock forecast is the largest
contributor, followed by measures updates.
2025 Natural Gas IRP Appendix 216

Table 7— Difference Between 2023 and 2025 Total First-Year Cost-Effective Achievable Potential
(Millions of Therms)
Difference: Share of
023 to 2025 Difference
Load and Stock Forecast -5.65 51%
Emerging Technology -0.82 7%
Measure Updates +3.75 34%
Avoided Costs -0.36 3%
Discount Rate -0.11 1%
CE Override +0.43 4%
Total -2.9
Deployed Results — Peak Day Results
In the state of Oregon and around the region, there is an increased focus on the peak savings
contributions of energy efficiency and the related impact on capacity investments. This new
focus has led some utilities to embark on efforts to avoid or delay distribution system
reinforcements. Therefore, Avista and Energy Trust have collaborated to develop estimates of
peak day contributions from the energy efficiency measures in the Energy Trust forecast.
Peak day coincident factors are the percentage of annual savings that occur on a peak day and
are shown in Table 8 below. Avista is still reviewing this methodology and for the purpose of this
analysis, Energy Trust utilized the peak day factors that are used in the avoided costs used to
screen measures for cost-effectiveness to determine the cost-effective achievable resource per
the description above. These include residential and commercial space heating factors
developed by NW Natural and hot water, process load (flat), and clothes washer factors sourced
from load shapes developed by the Northwest Power and Conservation Council for electric
measures that are analogous to gas equipment. The peak day factors are the highest for the
space heating load shapes, which align with a winter system peak that is typical of natural gas
utilities.
Table 8 - Peak Day Coincident Factors by Load Profile
Load Profile Peak Day Factor Source
Residential Space Heating 1.98% NW Natural
Commercial Space Heating 1.77% NW Natural
Water Heating 0.36% NWPCC
Clothes Washer 0.30% NWPCC
Process Load 0.20% NWPCC
Figure below shows the annual, deployed peak day savings potential based upon the results of
the 20-year forecast developed for this IRP. Each measure analyzed is assigned a load shape
and the appropriate peak day factor is applied to the annual savings to calculate the overall
DSM contribution to peak day capacity. This is equal to 219,871 total first-year therms in
Avista's Oregon service territory over the 20-year forecast, as shown in Table 9 below.
Figure 12 -Annual Deployed Peak Day DSM Savings Contribution by Sector9
2025 Natural Gas IRP Appendix 217

16,000
14,000
12,000
E 10,000
8,000
0
6,000
a
4,000
2,000
0
0`1� p 0`" 0�0 P or j0 o"' 03� 030 03� 03� 041 0�11 0 b 000 opo o o r, '5 ll*
ti � ti � ti ti ti ti ti ti ti ti � ti � ti � ti ti ti
■Commercial ■Residential _Industrial ■Exogenous
Table 9—Total First-Year Deployed Peak Day DSM Savings Contribution by Sector(Therms)
Sector Total First-Year Peak Day
Savings (Therms)
Residential 161,328
Commercial 50,995
Industrial 3,950
Exogenous 3,598
Total 219,871
Scenario Runs
For the 2025 IRP, Energy Trust modeled two scenarios for Avista—one looking at electrification
and another at high growth on the gas system. Both scenarios were designed to reflect
differences in avoided costs. These scenarios are outlined in the bullets below:
• Base Case: Expected load forecast with expected compliance and carbon prices and
system coincident peak factors.
• Electrification: Expected load forecast with high carbon and compliance prices and
system coincident peak factors.
• High Growth on the Gas System: Expected load forecast with low carbon and
compliance prices and system coincident peak factors.
Both scenarios resulted in extremely slight increases in cost-effective achievable potential in the
residential sector, as well as in commercial for the high growth scenario. Neither scenario
resulted in meaningful differences in savings potential and thus neither presented deployment
implications. These increases are driven by increases in cost-effective achievable potential for a
residential whole home pathway for both scenarios, and commercial efficient windows for the
high growth scenario. The inputs and results are summarized in tables 10 and 11 below.
2025 Natural Gas IRP Appendix 218

Table 10-Average Annual Avoided Costs 2025-2024
High Growth % Difference % Difference
Load Profile Reference on Gas Electrification Base to High Baseto
ACs System ACs ACs Growth on Electrification
Gas System
DHW $1.54 $1.61 $1.57 5% 2%
Flat $1.47 $1.54 $1.50 5% 3%
Res Heating $2.02 $2.07 $2.04 3% 1%
Com Heating $2.00 $2.05 $2.01 3% 1%
Clotheswasher $1.53 $1.61 $1.57 5% 3%
Table 11 -Cost-Effective Achievable Potential -Total First-Year Savings 2025-2044 (MM Therms)
High • Difference
Sector Reference on Gas Electrification Base to High Baseto
Growth on Electrification
Gas System
Residential 12.7758 12.7759 12.7759 0.0008% 0.0008%
Commercial 5.4517 5.4530 5.4517 0.0243% 0.0000%
Industrial 0.5307 0.5307 0.5307 0.0000% 0.0000%
Total 18.7581 18.7596 18.7582 0.0076% 0.0005%
2025 Natural Gas IRP Appendix 219

APPENDIX 4.3: ENVIRONMENTAL EXTERNALITIES OVERVIEW
(OREGON JURISDICTION ONLY)
The methodology for determining avoided costs from reduced incremental natural gas usage considers
commodity and variable transportation costs including new supply resource options as discussed in Chapter
6.
Per traditional economic theory and industry practice,an environmental externality factor is typically added
to the avoided cost when there is an opportunity to displace traditional supply-side resources with an
alternative resource with no adverse environmental impact.
REGULATORY GUIDANCE
The Oregon Public Utility Commission (OPUC) issued Order 93-965 (UM-424) to address how utilities
should consider the impact of environmental externalities in planning for future energy resources. The
Order required analysis on the potential natural gas cost impacts from emitting carbon dioxide (CO2) and
nitric-oxide(NOx).
The OPUC's Order No. 07-002 in Docket UM 1056 (Investigation Into Integrated Resource Planning)
established the following guideline for the treatment of environmental costs used by energy utilities that
evaluate demand-side and supply-side energy choices:
UM 1056, Guideline 8 -Environmental Costs
"Utilities should include, in their base-case analyses, the regulatory compliance costs they expect
for carbon dioxide(CO2), nitrogen oxides(NOx),sulfur oxides(SO2), and mercury(Hg)emissions.
Utilities should analyze the range of potential CO2 regulatory costs in Order No. 93-695,from $0
- $40 (1990$). In addition, utilities should perform sensitivity analysis on a range of reasonably
possible cost adders for nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury (Hg), if
applicable.
In June 2008,the OPUC issued Order 08-338(UM1302)which revised UM1056,Guideline 8.The revised
guideline requires the utility should construct a base case portfolio to reflect what it considers to be the
most likely regulatory compliance future for the various emissions. Additionally the guideline requires the
utility to develop several compliance scenarios ranging from the present CO2 regulatory level to the upper
reaches of credible proposals and each scenario should include a time profile of CO2 costs. The utility is
also required to include a"trigger point"analysis in which the utility must determine at what level of carbon
costs its selection of portfolio resources would be significantly different.
ANALYSIS
The supply-side implication of environmental externalities generally relates to combustion of fuel to move
or compress natural gas. Avista's direct gas distribution system infrastructure relies solely on the upstream
line pressure of the interstate pipeline transportation network to distribute natural gas to its customers and
thus does not directly combust fuels that result in any CO2,NOx, S02, or Hg emissions.
Upstream gas system infrastructure (pipelines, storage facilities, and gathering systems), however, do
produce CO2 emissions via compressors used to pressurize and move natural gas.
2025 Natural Gas IRP Appendix 220

APPENDIX-CHAPTER 3
Table 3.2.1 summarizes a range of environmental cost adders we believe capture several compliance futures
including our expected scenario.The CO2 cost adders reflect outlooks we obtained the social cost of carbon
at 2.5%and the cost of a community climate investment in the CPP.
The guidelines also call for a trigger point analysis that reflects a "turning point" at which an alternate
resource portfolio would be selected at different carbon cost adders levels. This can be found in Chapter 8.
Conceptually,there could be differing levels of cost adders applicable to pipeline transported supply versus
in service territory LNG storage gas. We do acknowledge there is influence to the avoided costs which
would impact the cost effectiveness of demand-side measures in the DSM business planning process.
CONSERVATION COST ADVANTAGE
For this IRP,we also incorporated a 10 percent environmental externality factor into our assessment of the
cost-effectiveness of existing demand-side management programs. Our assessment of prospective demand-
side management opportunities is based on an avoided cost stream that includes this 10 percent factor.
Environmental externalities were evaluated in the IRP by adding the cost per therm equivalent of the
externality cost values to supply-side resources as described in OPUC Order No. 93-965.
REGULATORY FILING
Avista will file revised cost-effectiveness limits (CELs) based upon the updated avoided costs available
from this IRP process within the prescribed regulatory timetable.
TABLE 1: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS SCC @ 2.5%
2026 2030 2035 2040 2045
$/short ton S .''0 S .''0 S 7?0 S 7.20 S 7?0
'c $/lb $ 0.00 S 0.00 S 0.00 $ 0.00 $ 0.00
c
a lbs/therm 0.0656 0.0656 0.0656 0.0656 0.0656
o NOx Adder
o z S/therm $ 0.00 $ 0.00 S 0.00 S 0.00 S 0.00
$/short ton $ 290 $ '90 S 290 S 290 S 290
o
° $/lb $ 0.15 $ 0.1> S 0.15 S 0.15 S 0.15
N lbs/therm 0.06556 0.06556 0.06556 0.06556 0.06556
o
u x NOx Adder
Z o
U $/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01 $ 0.01
Cnn $/Metric Ton $ 121.0 $ 139.53 $ 166.57 $ 199.91 $ 235.04
$/lb S 0.W149 $ 0.0633 $ 0.0756 $ 0.0907 S 0.1066
N
o lbs/therm 11.70 11.70 11.70 11.70 11.70
CO2 Adder
S'therill S 0.64228 1 S 0.74 1 S 0.88 $ 1.06 S 1.25
2025 Natural Gas IRP Appendix 221

TABLE 2: ENVIRONMENTAL EXTERNALITIES COST ADDER ANALYSIS CCI
2026 2030 2035 2040 2045
$/short ton $ 7 $ 7 $ 7 $ 7 $ 7
$/lb $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.00
r a lbs/therm 0.0656 0.0656 0.0656 0.0656 0.0656
E x NOx Adder
y Z $/them $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.00
a�
'c $/short ton $ 290 $ 290 $ 290 $ 290 $ 290
° $/lb $ 0.15 $ 0.15 $ 0.15 $ 0.15 $ 0.15
m
E_ lbs/thenn 0.066 0.066 0.066 0.066 0.066
v X NOx Adder
o
= z $/therm $ 0.01 $ 0.01 $ 0.01 $ 0.01 $ 0.01
E $/Metric Ton $ 141.00 $ 157.00 $ 182.00 $ 210.00 $ 241.00
o $/lb $ 0.0640 $ 0.0712 $ 0.0826 $ 0.0953 $ 0.1093
(,� N
o lbs/therm 11.7 11.7 11.7 11.7 11.7
CO2 Adder
$/thenn $ 0.75 $ 0.83 $ 0.97 $ 1.11 $ 1.28
2025 Natural Gas IRP Appendix 222

Energy Efficiency (DSM) Annual Savings
Idaho Oregon Washington Oregon Washingtoi---�-
. . . .
2026 26,257 48,408 71,740 12,657 20,752
2027 60,181 105,306 155,226 25,566 42,028
2028 101,353 166,262 251,510 39,049 64,022
2029 106,048 225,724 341,747 53,291 86,848
2030 141,546 294,020 448,283 68,517 110,865
2031 181,546 365,640 561,887 84,772 135,455
2032 224,383 440,160 681,346 101 ,614 160,122
2033 267,382 517,054 798,806 118,740 183,986
2034 312,308 596,059 916,396 135,579 207,156
2035 355,518 677,047 1 ,028,874 151,714 229,109
2036 394,823 759,353 1,133,217 166,580 248,943
2037 426,656 842,415 11218,622 179,721 265,384
2038 454,871 926,695 1,296,341 191,436 280,040
2039 479,244 1,012,099 1,362,119 201,890 292,485
2040 503,271 1,098,821 1,424,373 211,621 304,387
2041 524,167 1,187,438 1,473,597 220,368 314,880
2042 543,024 1,278,357 1,512,186 228,404 323,398
2043 562,880 1,370,722 1,550,262 236,365 332,519
2044 582,937 1,464,778 1,581,395 243,971 341,024
2045 600,730 1,547,925 1,601,274 251,405 349,006
Energy Efficiency (DSM) Annual Cost (Nominal $)
Oregon Washington
Transport . .
2026 $528,778 $6,845,874 $1,485,107 $5,324 $156,841
2027 $745,955 $6,930,404 $1,816,533 $6,236 $168,077
2028 $933,912 $7,080,727 $2,207,958 $7,802 $178,068
2029 $873,134 $7,255,709 $2,602,190 $9,169 $187,374
2030 $1,028,222 $7,621,501 $3,078,456 $10,763 $197,334
2031 $1,184,679 $8,188,909 $3,583,955 $12,554 $203,539
2032 $1,298,846 $8,618,797 $4,004,802 $13,751 $198,147
2033 $1,387,076 $8,954,438 $4,342,127 $15,925 $193,640
2034 $1,483,242 $8,976,248 $4,559,960 $16,123 $190,133
2035 $1,493,308 $9,279,905 $4,581,568 $17,515 $184,948
2036 $1,460,326 $9,248,141 $4,454,170 $16,632 $178,180
2037 $1,358,423 $9,080,747 $4,175,945 $14,890 $157,649
Avista Corp 2025 Gas IRP DRAFT 1
2025 Natural Gas IRP Appendix 223

2038 $1,306,152 $9,033,593 $3,844,128 $13,647 $142,085
2039 $1,265,341 $9,048,727 $3,484,161 $12,237 $129,517
2040 $1,270,941 $9,225,634 $3,106,657 $10,918 $118,181
2041 $1,268,212 $9,227,929 $2,733,846 $9,803 $107,267
2042 $1,268,922 $9,482,001 $2,348,103 $10,539 $90,970
2043 $1,289,687 $9,362,904 $2,060,676 $10,142 $84,619
2044 $1,321,965 $9,594,980 $1,619,383 $8,862 $77,834
2045 $1,365,110 $8,466,124 $1,382,268 $8,888 $77,498
Avista Corp 2025 Gas IRP DRAFT 2
2025 Natural Gas IRP Appendix 224

NATURAL GAS COST PER DEKATHERM (NOMINAL $) -
EXPECTED
AECO Basin
2026 3.08 2.68 2.38 2.19 2.32 2.45 2.61 2.65 2.57 2.54 2.87 3.31
2027 3.50 3.34 2.84 2.44 2.39 2.58 2.69 2.70 2.62 2.71 3.01 3.34
2028 3.70 3.41 2.95 2.51 2.51 2.59 2.69 2.71 2.53 2.57 3.24 3.42
2029 3.82 3.52 3.01 2.50 2.49 2.67 2.78 2.74 2.58 2.62 3.08 3.47
2030 3.82 3.63 3.34 2.79 2.61 2.69 2.73 2.72 2.52 2.55 3.25 3.44
2031 3.71 3.37 3.06 2.80 2.81 2.91 2.96 2.96 2.75 2.88 3.34 3.66
2032 3.78 3.39 3.13 2.99 3.01 3.03 3.12 3.15 3.02 3.06 3.64 3.93
2033 4.07 3.83 3.52 3.31 3.32 3.34 3.45 3.45 3.17 3.21 3.81 4.06
2034 4.22 3.99 3.64 3.50 3.51 3.54 3.62 3.64 3.38 3.41 3.99 4.18
2035 4.43 4.07 3.79 3.60 3.60 3.67 3.77 3.75 3.56 3.60 4.19 4.35
2036 4.50 4.20 3.90 3.81 3.83 3.84 3.97 3.95 3.73 3.78 4.33 4.64
2037 4.72 4.37 4.05 3.93 3.88 3.91 4.04 4.01 3.84 3.92 4.49 4.66
2038 4.93 4.60 4.26 4.05 4.06 4.08 4.25 4.12 4.04 4.04 4.79 4.97
2039 5.16 4.78 4.41 4.16 4.17 4.19 4.31 4.19 4.05 4.13 4.95 5.09
2040 5.52 5.16 4.75 4.47 4.48 4.56 4.68 4.54 4.45 4.54 5.32 5.43
2041 5.61 5.33 4.87 4.62 4.64 4.62 4.75 4.65 4.58 4.67 5.44 5.71
2042 5.91 5.53 5.12 4.79 4.82 4.87 4.90 4.78 4.67 4.81 5.67 5.85
2043 5.95 5.66 5.20 4.87 4.89 4.93 5.05 4.98 4.87 4.93 5.79 6.00
2044 6.28 5.93 5.50 5.08 5.08 5.17 5.30 5.11 5.09 5.18 6.00 6.21
2045 6.51 6.15 5.68 5.27 5.27 5.42 5.50 5.27 5.29 5.44 6.34 6.54
Malin Basin
2026 4.10 3.72 3.38 3.04 3.02 3.00 3.35 3.44 3.41 3.51 3.82 4.15
2027 4.43 4.42 3.76 3.19 3.13 3.04 3.25 3.26 3.26 3.58 3.87 4.23
2028 4.62 4.09 3.67 3.17 3.14 2.94 3.15 3.15 3.38 3.60 3.89 4.12
2029 4.68 4.11 3.54 3.12 3.04 3.03 3.10 3.18 3.35 3.48 4.14 4.51
2030 5.01 4.47 4.09 3.40 3.13 3.04 3.01 3.15 3.38 3.50 4.24 4.82
2031 5.14 4.29 3.86 3.41 3.23 3.26 3.27 3.42 3.55 3.71 4.28 4.81
2032 5.05 4.26 3.85 3.44 3.51 3.45 3.57 3.77 3.85 4.01 4.66 5.14
2033 5.43 4.80 4.34 3.88 3.79 3.77 3.78 3.92 4.04 4.22 4.87 5.35
2034 5.63 4.89 4.42 4.09 3.99 3.99 4.00 4.17 4.22 4.40 5.01 5.36
2035 5.57 4.98 4.55 4.12 4.02 3.91 3.92 4.30 4.47 4.38 5.12 5.30
2036 5.40 4.82 4.53 4.24 4.18 4.18 4.19 4.21 4.30 4.51 5.11 5.36
2037 5.45 4.88 4.56 4.77 4.73 4.38 4.36 4.36 4.48 4.68 5.38 5.54
2038 5.75 5.13 4.91 4.55 4.50 4.52 4.49 4.47 4.59 4.82 5.39 6.03
2039 6.29 5.38 5.14 4.70 4.65 4.64 4.63 4.61 4.70 4.91 5.48 5.66
2025 Natural Gas IRP Appendix 225

2040 6.11 5.70 5.50 4.99 5.00 5.04 5.01 5.54 5.61 5.26 5.79 6.00
2041 5.61 5.33 4.87 4.62 4.64 4.62 4.75 4.65 4.58 4.67 5.44 5.71
2042 5.91 5.53 5.12 4.79 4.82 4.87 4.90 4.78 4.67 4.81 5.67 5.85
2043 5.95 5.66 5.20 4.87 4.89 4.93 5.05 4.98 4.87 4.93 5.79 6.00
2044 6.28 5.93 5.50 5.08 5.08 5.17 5.30 5.11 5.09 5.18 6.00 6.21
2045 6.51 6.15 5.68 5.27 5.27 5.42 5.50 5.27 5.29 5.44 6.34 6.54
Rockies Basin
FUNEV-7111111l1 1
2026 4.21 3.84 3.22 2.81 2.79 3.19 3.05 3.22 3.26 3.28 3.86 4.53
2027 4.60 4.41 3.69 3.17 3.10 3.28 3.23 3.31 3.37 3.28 3.95 4.58
2028 4.85 4.46 3.62 3.19 3.24 3.40 3.45 3.51 3.37 3.37 3.99 4.50
2029 4.69 4.33 3.68 3.28 3.33 3.43 3.45 3.48 3.45 3.51 4.12 4.54
2030 4.87 4.54 4.14 3.59 3.43 3.46 3.48 3.50 3.53 3.61 4.22 4.62
2031 4.86 4.44 3.98 3.71 3.66 3.65 3.73 3.77 3.84 3.89 4.41 4.73
2032 5.00 4.63 4.24 3.95 3.87 3.85 3.85 3.89 3.93 4.02 4.63 4.96
2033 5.22 4.88 4.55 4.14 4.08 4.09 4.14 4.16 4.20 4.30 4.89 5.17
2034 5.32 5.09 4.74 4.42 4.30 4.36 4.40 4.45 4.47 4.60 5.12 5.47
2035 5.64 5.31 4.92 4.53 4.39 4.47 4.49 4.50 4.58 4.67 5.29 5.55
2036 5.65 5.31 4.98 4.68 4.60 4.61 4.63 4.68 4.80 4.89 5.48 5.75
2037 5.81 5.50 5.20 4.89 4.76 4.76 4.78 4.83 4.90 5.06 5.73 5.93
2038 6.16 5.83 5.40 5.04 4.96 4.96 4.98 4.98 5.08 5.23 5.86 6.04
2039 6.30 5.94 5.53 5.19 5.07 5.11 5.12 5.13 5.23 5.37 6.00 6.20
2040 6.68 6.35 5.92 5.58 5.50 5.55 5.54 5.51 5.63 5.75 6.42 6.62
2041 6.79 6.48 6.02 5.67 5.59 5.61 5.65 5.67 5.74 5.87 6.54 6.73
2042 6.98 6.70 6.23 5.85 5.76 5.80 5.84 5.88 5.95 6.05 6.74 6.94
2043 7.12 6.79 6.36 5.93 5.86 5.89 5.94 5.96 6.05 6.17 6.84 7.05
2044 7.44 7.13 6.67 6.22 6.14 6.17 6.22 6.22 6.33 6.45 7.11 7.39
2045 7.66 7.39 6.87 6.41 6.34 6.36 6.39 6.40 6.53 6.65 7.36 7.61
Stanfield Basin
OctYear Jan I�JW Apr May Jun Jul Aug Sep D-
2026 3.88 3.55 3.11 2.82 2.88 2.80 3.11 3.17 3.12 3.24 3.60 3.98
2027 4.26 4.15 3.46 2.99 2.89 2.78 2.96 3.08 3.10 3.24 3.64 4.04
2028 4.43 3.95 3.42 3.03 3.00 2.80 2.91 2.92 3.13 3.27 3.76 4.03
2029 4.26 3.82 3.29 2.86 2.90 2.91 2.92 2.95 3.18 3.36 3.88 4.09
2030 4.75 4.28 3.91 3.23 3.02 2.97 2.96 3.10 3.22 3.42 4.13 4.60
2031 4.79 4.11 3.67 3.22 3.17 3.19 3.20 3.31 3.42 3.62 4.18 4.66
2032 4.73 4.15 3.72 3.31 3.35 3.40 3.47 3.56 3.63 3.84 4.48 4.93
2033 5.13 4.54 4.18 3.66 3.66 3.66 3.67 3.75 3.85 4.10 4.70 5.03
2034 5.15 4.65 4.30 3.89 3.88 3.90 3.90 3.96 4.05 4.32 4.83 5.18
2035 5.31 4.84 4.42 3.93 3.86 3.84 3.79 3.91 4.01 4.32 4.91 5.15
2036 5.16 4.76 4.41 4.10 4.07 4.12 4.10 4.10 4.18 4.45 4.98 5.22
2025 Natural Gas IRP Appendix 226

2037 5.20 4.77 4.51 4.32 4.28 4.31 4.27 4.30 4.38 4.65 5.20 5.45
2038 5.55 5.10 4.82 4.47 4.44 4.43 4.38 4.43 4.52 4.76 5.26 5.46
2039 5.59 5.25 5.05 4.61 4.58 4.58 4.51 4.56 4.64 4.86 5.38 5.54
2040 5.96 5.65 5.37 4.92 4.95 4.99 4.90 4.95 4.95 5.21 5.67 5.89
2041 6.10 5.75 5.52 5.03 4.99 4.97 5.00 5.07 5.04 5.27 5.77 6.01
2042 6.29 6.01 5.77 5.28 5.29 5.32 5.26 5.31 5.36 5.56 6.03 6.23
2043 6.44 6.17 5.89 5.40 5.39 5.38 5.36 5.42 5.48 5.67 6.12 6.39
2044 6.75 6.47 6.21 5.68 5.66 5.66 5.60 5.73 5.74 5.95 6.41 6.70
2045 7.00 6.75 6.41 5.90 5.81 5.78 5.67 5.84 5.84 6.10 6.64 6.92
Station 2 Basin
• •
202763�. 0 2.62 2.28 2.13 2.26 2.39 2.54 2.57 2.52 2.47 2.78 3.22
2021 3.31 2.75 2.38 2.34 2.53 2.68 2.63 2.56 2.62 2.90 3.23
2028 3.57 3.35 2.85 2.38 2.37 2.49 2.62 2.62 2.41 2.45 3.10 3.27
2029 3.71 3.45 2.86 2.40 2.39 2.56 2.71 2.66 2.43 2.47 2.92 3.33
2030 3.65 3.51 3.17 2.72 2.54 2.62 2.70 2.67 2.41 2.44 3.12 3.32
2031 3.57 3.34 2.94 2.75 2.76 2.84 2.90 2.90 2.64 2.77 3.28 3.54
2032 3.63 3.33 2.98 2.89 2.89 2.91 3.00 3.02 2.87 2.90 3.49 3.78
2033 3.89 3.73 3.34 3.19 3.19 3.20 3.30 3.28 3.00 3.03 3.63 3.87
2034 4.00 3.80 3.43 3.34 3.35 3.37 3.46 3.45 3.21 3.24 3.83 3.96
2035 4.19 3.97 3.54 3.43 3.44 3.50 3.57 3.51 3.35 3.39 3.94 4.07
2036 4.19 4.00 3.63 3.65 3.72 3.73 3.88 3.81 3.62 3.67 4.22 4.49
2037 4.37 4.12 3.77 3.82 3.81 3.83 3.98 3.90 3.74 3.80 4.42 4.55
2038 4.78 4.52 4.09 3.94 3.95 3.97 4.08 3.93 3.88 3.87 4.62 4.78
2039 4.95 4.68 4.18 4.01 4.02 4.03 4.15 4.02 3.89 3.95 4.78 4.90
2040 5.32 5.00 4.54 4.33 4.35 4.41 4.49 4.26 4.24 4.31 5.14 5.22
2041 5.38 5.18 4.62 4.39 4.40 4.39 4.51 4.38 4.31 4.38 5.24 5.45
2042 5.68 5.35 4.80 4.59 4.61 4.63 4.60 4.50 4.37 4.47 5.02 5.51
2043 5.60 5.29 4.68 4.72 4.74 4.71 4.79 4.86 4.61 4.56 5.24 5.66
2044 5.94 5.41 4.86 4.97 5.00 5.00 5.06 4.83 4.87 4.85 5.64 5.91
2045 6.22 5.68 5.19 5.13 5.16 5.18 5.20 4.82 4.97 5.03 6.01 6.19
Sumas Basin
Oct
2026 4.05 3.67 3.08 2.69 2.77 3.107 3.25 3.24 3.16 3.23 3.78 4.23
2027 4.48 4.37 3.58 2.94 2.90 2.89 2.95 2.95 2.98 3.18 3.87 4.33
2028 4.75 4.45 3.51 2.77 2.92 2.99 2.97 3.07 3.04 3.19 3.81 4.14
2029 4.36 4.06 3.54 2.93 2.92 2.95 2.95 2.96 3.06 3.27 3.88 4.66
2030 4.83 4.34 4.01 3.20 3.03 2.99 2.91 2.96 3.07 3.17 3.97 4.73
2031 5.01 4.20 3.84 3.25 3.23 3.22 3.19 3.26 3.33 3.53 4.15 4.83
2032 5.00 4.32 4.01 3.39 3.41 3.43 3.42 3.45 3.49 3.66 4.37 5.07
2033 5.32 4.73 4.30 3.71 3.71 3.73 3.71 3.75 3.80 3.86 4.62 5.29
2025 Natural Gas IRP Appendix 227

2034 5.41 4.92 4.41 4.02 3.91 3.95 3.93 4.05 3.99 3.97 4.88 5.59
2035 5.81 5.11 4.68 3.98 3.95 3.92 3.91 3.92 4.08 4.27 4.99 5.66
2036 5.78 4.94 4.72 4.20 4.14 4.09 4.18 4.21 4.16 4.42 5.14 5.62
2037 5.70 5.14 4.64 4.37 4.30 4.34 4.31 4.32 4.39 4.53 5.31 5.69
2038 5.93 5.41 5.06 4.51 4.49 4.52 4.48 4.46 4.53 4.64 5.52 5.65
2039 5.86 5.43 5.20 4.66 4.64 4.64 4.62 4.55 4.66 4.77 5.70 5.87
2040 6.31 5.88 5.53 4.98 4.97 5.01 5.00 4.96 5.00 5.14 6.11 6.27
2041 6.47 6.07 5.63 5.11 5.09 5.07 5.07 5.07 5.13 5.24 6.21 6.44
2042 6.70 6.27 5.92 5.36 5.33 5.39 5.34 5.29 5.38 5.48 6.50 6.66
2043 6.82 6.38 6.03 5.49 5.48 5.52 5.44 5.41 5.51 5.56 6.64 6.84
2044 7.20 6.69 6.26 5.77 5.78 5.79 5.74 5.69 5.75 5.90 6.86 7.17
2045 7.47 6.98 6.47 6.09 6.11 6.02 5.90 5.88 5.93 6.08 7.16 7.41
NATURAL GAS COST PER DEKATHERM (NOMINAL $) - HIGH
AECO Basin
2026 3.22 2.88 2.69 2.57 2.77 2.98 3.25 3.35 3.31 3.43 3.74 4.19
2027 4.48 4.36 3.90 3.49 3.36 3.65 3.82 3.94 3.78 3.85 4.19 4.68
2 228 5.04 4.80 4.28 3.91 3.87 3.90 3.99 4.19 4.06 4.25 4.72 5.15
2029 5.66 5.36 4.92 4.37 4.23 4.64 4.58 4.56 4.31 4.31 5.00 5.39
2030 5.75 5.55 5.20 4.83 4.68 4.71 4.77 4.76 4.36 4.61 5.27 5.40
2031 5.68 5.18 4.86 4.66 4.70 4.83 4.96 5.08 4.74 4.86 5.39 5.70
2032 5.97 5.81 5.70 5.48 5.51 5.84 5.92 5.91 5.73 6.08 6.45 6.70
2033 7.12 7.04 6.70 6.23 6.31 6.23 6.26 6.30 6.16 6.06 6.71 6.96
2034 7.59 6.93 6.74 6.63 6.70 6.81 7.22 7.23 7.21 7.22 7.71 8.00
2035 7.94 7.68 7.46 7.30 7.21 7.29 7.36 7.50 7.20 7.41 7.85 8.07
2036 8.32 7.87 7.57 7.48 7.24 7.92 7.98 7.82 7.62 7.76 8.25 8.57
2037 8.44 8.65 8.16 8.28 7.99 8.07 8.03 7.88 7.72 7.92 8.45 8.81
2038 9.50 9.16 8.73 8.37 8.22 8.24 8.37 8.06 8.51 8.36 9.19 9.33
2039 9.64 9.45 9.26 9.33 9.18 8.89 9.41 9.40 9.09 8.82 9.59 10.43
2040 11.24 11.08 10.75 10.30 10.21 10.04 10.62 10.34 9.94 10.04 10.95 10.93
2041 11.21 10.61 10.58 9.83 9.48 10.02 10.34 10.17 10.13 9.75 10.46 11.13
2042 11.38 10.98 10.09 10.11 10.42 10.06 10.02 9.63 10.24 10.16 10.94 11.06
2043 11.01 11.43 10.76 10.28 10.24 10.22 10.83 10.86 10.30 10.90 12.10 12.68
2044 12.59 11.92 11.58 10.85 11.68 11.50 11.85 11.05 11.13 10.95 12.78 13.47
2045 13.71 12.86 12.31 11.65 11.36 11.34 11.64 11.20 11.42 11.43 12.67 14.12
Malin Basin
FebYear Jan Mar AprAug Sep Oct •
2026 4.24 3.92 3.70 3.43 3.47 3.53 3.99 4.14 4.15 4.41 4.69 5.03
2027 5.41 5.44 4.81 4.24 4.10 4.11 4.37 4.50 4.43 4.72 5.05 5.57
2028 5.96 5.48 5.00 4.57 4.51 4.25 4.44 4.63 4.90 5.28 5.37 5.85
2025 Natural Gas IRP Appendix 228

2029 6.52 5.96 5.45 4.99 4.78 5.00 4.90 4.99 5.08 5.17 6.05 6.43
2030 6.95 6.39 5.94 5.43 5.20 5.06 5.05 5.18 5.22 5.56 6.26 6.77
2031 7.11 6.10 5.66 5.27 5.12 5.18 5.27 5.53 5.54 5.69 6.33 6.85
2032 7.25 6.68 6.42 5.93 6.01 6.26 6.37 6.53 6.56 7.04 7.47 7.91
2033 8.49 8.01 7.52 6.79 6.78 6.66 6.58 6.77 7.02 7.06 7.76 8.25
2034 9.01 7.84 7.53 7.23 7.18 7.27 7.60 7.76 8.06 8.21 8.74 9.19
2035 9.08 8.59 8.22 7.83 7.63 7.53 7.51 8.05 8.10 8.19 8.78 9.01
2036 9.21 8.48 8.20 7.91 7.59 8.26 8.20 8.09 8.19 8.48 9.03 9.28
2037 9.17 9.16 8.68 9.12 8.85 8.54 8.35 8.23 8.36 8.69 9.35 9.69
2038 10.31 9.70 9.38 8.88 8.67 8.68 8.61 8.40 9.06 9.14 9.79 10.38
2039 10.78 10.05 9.99 9.87 9.66 9.34 9.73 9.81 9.74 9.60 10.13 11.00
2040 11.83 11.63 11.50 10.82 10.73 10.53 10.94 11.35 11.10 10.77 11.43 11.50
2041 11.82 11.08 11.28 10.33 9.92 10.45 10.66 10.63 10.64 10.42 10.92 11.49
2042 11.82 11.51 10.84 11.36 11.64 10.56 10.51 10.21 10.98 10.95 11.46 11.51
2043 11.54 12.00 11.55 10.88 10.78 10.77 11.26 11.35 10.97 11.69 12.58 13.87
2044 13.94 12.51 12.34 11.55 12.34 12.07 12.30 11.72 11.84 11.78 13.37 14.00
2045 14.28 13.52 13.09 12.35 12.04 11.78 11.98 12.66 12.93 12.15 13.14 14.56
Rockies Basin
May Jun Jull 17,
2026 4.35 4.04 3.54 3.19 3.24 3.72 3.69 3.92 4.00 4.18 4.73 5.41
2027 5.58 5.43 4.75 4.22 4.07 4.35 4.36 4.55 4.53 4.42 5.13 5.91
2028 6.19 5.85 4.95 4.59 4.60 4.70 4.74 4.99 4.90 5.05 5.47 6.23
2029 6.52 6.17 5.59 5.16 5.06 5.40 5.25 5.30 5.18 5.20 6.04 6.46
2030 6.80 6.47 5.99 5.62 5.50 5.48 5.51 5.53 5.37 5.67 6.24 6.58
2031 6.83 6.25 5.78 5.57 5.56 5.57 5.73 5.88 5.83 5.87 6.45 6.76
2032 7.19 7.05 6.81 6.43 6.37 6.66 6.66 6.65 6.64 7.04 7.44 7.73
2033 8.28 8.09 7.73 7.06 7.07 6.98 6.95 7.01 7.19 7.15 7.78 8.06
2034 8.69 8.03 7.85 7.56 7.49 7.63 8.00 8.04 8.31 8.41 8.85 9.29
2035 9.15 8.92 8.59 8.23 8.00 8.09 8.08 8.25 8.21 8.48 8.95 9.27
2036 9.46 8.97 8.65 8.35 8.01 8.69 8.64 8.55 8.69 8.87 9.40 9.67
2037 9.53 9.78 9.31 9.24 8.88 8.92 8.77 8.70 8.78 9.06 9.69 10.08
2038 10.73 10.39 9.87 9.36 9.12 9.12 9.11 8.91 9.56 9.55 10.27 10.39
2039 10.79 10.61 10.38 10.36 10.08 9.81 10.22 10.33 10.27 10.06 10.65 11.55
2040 12.40 12.28 11.92 11.41 11.23 11.03 11.48 11.32 11.13 11.26 12.05 12.12
2041 12.40 11.76 11.73 10.87 10.44 11.01 11.25 11.18 11.29 10.95 11.56 12.15
2042 12.45 12.15 11.20 11.18 11.36 10.99 10.96 10.73 11.52 11.39 12.01 12.15
2043 12.18 12.57 11.92 11.34 11.21 11.19 11.71 11.84 11.48 12.15 13.16 13.73
2044 13.74 13.12 12.74 11.99 12.73 12.49 12.77 12.16 12.37 12.23 13.89 14.64
2045 14.86 14.10 13.50 12.79 12.43 12.28 12.53 12.32 12.67 12.64 13.70 15.20
Stanfield Basin
2025 Natural Gas IRP Appendix 229

2026 4.02 3.75 3.43 3.21 3.33 3.33 3.75 3.87 3.86 4.14 4.47 4.86
2027 5.24 5.17 4.51 4.04 3.86 3.85 4.08 4.32 4.27 4.38 4.82 5.38
2028 5.77 5.34 4.75 4.43 4.37 4.11 4.20 4.40 4.65 4.95 5.24 5.76
2029 6.10 5.67 5.20 4.74 4.64 4.89 4.72 4.76 4.91 5.06 5.80 6.01
2030 6.68 6.20 5.76 5.26 5.09 4.99 4.99 5.14 5.06 5.48 6.15 6.56
2031 6.76 5.92 5.47 5.08 5.07 5.11 5.20 5.42 5.41 5.60 6.23 6.69
2032 6.92 6.56 6.29 5.80 5.85 6.20 6.27 6.32 6.35 6.87 7.29 7.70
2033 8.19 7.75 7.36 6.58 6.65 6.55 6.47 6.60 6.84 6.94 7.59 7.92
2034 8.53 7.59 7.40 7.02 7.07 7.17 7.50 7.55 7.89 8.13 8.55 9.00
2035 8.82 8.45 8.09 7.64 7.47 7.46 7.38 7.66 7.65 8.13 8.57 8.87
2036 8.98 8.42 8.08 7.77 7.49 8.20 8.11 7.97 8.07 8.42 8.90 9.14
2037 8.92 9.05 8.62 8.68 8.39 8.47 8.25 8.16 8.26 8.65 9.17 9.60
2038 10.11 9.66 9.29 8.80 8.60 8.59 8.51 8.37 9.00 9.09 9.66 9.81
2039 10.08 9.93 9.90 9.78 9.59 9.29 9.62 9.76 9.68 9.55 10.03 10.88
2040 11.68 11.58 11.37 10.75 10.68 10.48 10.84 10.75 10.45 10.72 11.30 11.39
2041 11.71 11.03 11.23 10.24 9.84 10.37 10.59 10.58 10.59 10.36 10.78 11.44
2042 11.75 11.46 10.75 10.61 10.89 10.51 10.38 10.16 10.93 10.90 11.30 11.44
2043 11.50 11.95 11.44 10.81 10.74 10.68 11.14 11.30 10.91 11.65 12.43 13.07
2044 13.05 12.46 12.28 11.45 12.25 11.99 12.14 11.68 11.78 11.73 13.19 13.95
2045 14.20 13.47 13.04 12.29 11.90 11.70 11.81 11.77 11.97 12.09 12.98 14.51
Station 2 Basin
Year Jan Feb Mar Apr Mam
2026 3.14 2.82 2.60 2.51 2.71 1 2.92 3.18 3.28 3.26 3.37 3.66 4.09
2027 4.39 4.32 3.81 3.43 3.31 3.60 3.80 3.87 3.73 3.76 4.08 4.56
2028 4.91 4.73 4.19 3.78 3.74 3.80 3.91 4.10 3.94 4.13 4.58 5.00
2029 5.55 5.29 4.77 4.28 4.13 4.54 4.50 4.47 4.16 4.16 4.84 5.25
2030 5.58 5.43 5.02 4.75 4.61 4.64 4.73 4.71 4.25 4.50 5.14 5.27
2031 5.54 5.15 4.74 4.61 4.66 4.75 4.90 5.02 4.63 4.75 5.32 5.57
2032 5.82 5.74 5.54 5.37 5.40 5.72 5.81 5.78 5.58 5.93 6.30 6.55
2033 6.95 6.94 6.52 6.10 6.18 6.09 6.10 6.13 5.98 5.88 6.52 6.76
2034 7.37 6.75 6.54 6.48 6.55 6.64 7.06 7.04 7.04 7.05 7.56 7.79
2035 7.70 7.58 7.21 7.14 7.06 7.11 7.16 7.26 6.98 7.20 7.60 7.79
2036 8.01 7.66 7.30 7.32 7.13 7.81 7.89 7.68 7.51 7.64 8.14 8.41
2037 8.08 8.40 7.88 8.17 7.92 7.99 7.97 7.77 7.61 7.80 8.38 8.69
2038 9.34 9.09 8.56 8.27 8.11 8.13 8.20 7.86 8.35 8.20 9.02 9.13
2039 9.43 9.36 9.03 9.18 9.03 8.73 9.25 9.22 8.93 8.64 9.43 10.25
2040 11.04 10.92 10.54 10.16 10.07 9.89 10.43 10.07 9.74 9.82 10.77 10.72
2041 10.99 10.46 10.33 9.59 9.25 9.78 10.11 9.90 9.86 9.46 10.26 10.88
2042 11.15 10.80 9.78 9.91 10.20 9.82 9.72 9.35 9.93 9.81 10.29 10.72
2043 10.66 11.07 10.23 10.13 10.09 10.01 10.56 10.74 10.04 10.54 11.56 12.34
2044 12.24 11.40 10.94 10.75 11.59 11.32 11.61 10.78 10.91 10.62 12.41 13.17
2045 13.42 12.40 11.82 11.51 11.25 11.09 11.34 10.74 11.11 11.02 12.35 13.78
2025 Natural Gas IRP Appendix 230

Sumas Basin
• . - • •
2026 4.19 3.87 3.40 3.08 3.22 3.63 3.89 3.94 3.90 4.13 4.65 5.11
2027 5.46 5.39 4.63 3.99 3.87 3.96 4.07 4.19 4.15 4.32 5.05 5.67
2028 6.09 5.84 4.84 4.17 4.29 4.30 4.26 4.55 4.56 4.87 5.29 5.87
2029 6.20 5.90 5.45 4.81 4.66 4.93 4.74 4.77 4.79 4.96 5.80 6.59
2030 6.76 6.26 5.86 5.23 5.11 5.01 4.94 4.99 4.91 5.23 5.99 6.69
2031 6.98 6.01 5.64 5.11 5.12 5.14 5.19 5.37 5.32 5.51 6.20 6.86
2032 7.20 6.74 6.57 5.87 5.91 6.23 6.22 6.21 6.20 6.69 7.18 7.84
2033 8.38 7.94 7.47 6.63 6.70 6.62 6.51 6.60 6.78 6.71 7.52 8.19
2034 8.79 7.87 7.51 7.16 7.11 7.22 7.53 7.64 7.82 7.78 8.61 9.41
2035 9.32 8.72 8.36 7.69 7.56 7.54 7.50 7.67 7.71 8.08 8.65 9.38
2036 9.59 8.60 8.39 7.87 7.55 8.17 8.19 8.09 8.06 8.39 9.06 9.54
2037 9.41 9.42 8.75 8.72 8.42 8.50 8.30 8.19 8.27 8.54 9.27 9.84
2038 10.49 9.98 9.52 8.84 8.65 8.68 8.61 8.40 9.01 8.96 9.92 10.00
2039 10.34 10.10 10.05 9.83 9.65 9.34 9.72 9.75 9.70 9.46 10.34 11.21
2040 12.03 11.80 11.53 10.81 10.70 10.49 10.93 10.77 10.50 10.64 11.74 11.77
2041 12.08 11.35 11.33 10.32 9.94 10.47 10.66 10.58 10.67 10.33 11.23 11.87
2042 12.17 11.72 10.89 10.69 10.93 10.59 10.46 10.14 10.94 10.83 11.77 11.87
2043 11.89 12.16 11.58 10.90 10.83 10.81 11.22 11.29 10.94 11.54 12.95 13.52
2044 13.51 12.68 12.34 11.55 12.37 12.12 12.29 11.63 11.79 11.68 13.64 14.43
2045 14.67 13.70 13.10 12.47 12.20 11.94 12.04 11.81 12.06 12.07 13.50 15.00
2025 Natural Gas IRP Appendix 231

s r0
11
'I 'DROGEI I
- - LK,
0 1 AJ-1.-AL-1 = jWMN -
ti r
March
2025
Low Carbon . Resources .and
Offsets for •
NW Natural, Avista, • Cascade
Submitted to: Submitted by:
Matt Doyle ICF Resources, L.L.C.
NW Natural 1902 Reston Metro Plaza
[e-mail] Reston, VA 20190
703.934.3000
Tom Pardee
Avista Utilities
[e-mail]
Brian Robertson `I /
Cascade Natural Gas Corporation
[e-mail] '' C F
2025 Natural Gas IRP Appendix 232

\i/
.,*IC Alternative Fuels Analysis — NW Natural, Avista, and Cascade IRP Support March 2025
Table of Contents
ExecutiveSummary....................................................................................................................................................................................................................1
Introduction.....................................................................................................................................................................................................................................3
Overviewof ICF's Approach................................................................................................................................................................................................3
RenewableNatural Gas...........................................................................................................................................................................................................4
Hydrogen........................................................................................................................................................................................................................................23
SyntheticMethane..................................................................................................................................................................................................................44
RenewableThermal Certificates...................................................................................................................................................................................55
CarbonCapture, Use, and Storage.............................................................................................................................................................................64
CarbonIntensity Modelling...............................................................................................................................................................................................74
Stochastic Modeling for Simulated Values...........................................................................................................................................................77
Appendix........................................................................................................................................................................................................................................84
CONFIDENTIAL i 2025 Natural Gas IRP Appendix 233

\I/
**ICF Alternative Fuels Analysis - NW Natural,Avista, and Cascade IRP Support March 2025
List of Exhibits
Exhibit1. List of RNG Feedstocks.....................................................................................................................................................................................4
Exhibit 2. List of Data Sources for RNG Feedstock Inventory....................................................................................................................5
Exhibit 3. Landfill Gas Constituents and Corresponding Upgrading Technologies....................................................................7
Exhibit 4. RNG Resource Potential Projection Base Case Results (million MMBtu/y) (OR &WA)...................................9
Exhibit 5. RNG Resource Potential Projection Base Case Results (million MMBtu/y) (National)....................................10
Exhibit 6. Illustrative ICF RNG Cost Assumptions.............................................................................................................................................10
Exhibit 7.Cost Consideration in LCOE Analysis for RNG from Animal Manure...........................................................................12
Exhibit 8. Example Facility-Level Cost Inputs for RNG from Animal Manure................................................................................13
Exhibit 9. Cost Consideration in LCOE Analysis for RNG from Food Waste Digesters.........................................................13
Exhibit 10. Example Facility-Level Cost Inputs for RNG from Food Waste.....................................................................................14
Exhibit 11. Cost Consideration in LCOE Analysis for RNG from Landfill Gas...................................................................................15
Exhibit 12. Example Facility-Level Cost Inputs for RNG from LFG.........................................................................................................15
Exhibit 13.Cost Consideration in LCOE Analysis for RNG from WRRFs.............................................................................................16
Exhibit 14. Example Facility-Level Cost Inputs for RNG from WRRFs.................................................................................................16
Exhibit 15. RNG Levelized Cost Projection Base Case Results (Oregon and Washington,$/MMBtu)..........................17
Exhibit 16. RNG Levelized Cost Projection Base Case Results (National,$/MMBtu).................................................................17
Exhibit 17.Summary of Monte Carlo Simulation Results for RNG in Oregon and Washington (2030)........................17
Exhibit 18. Summary of Monte Carlo Simulation Results for RNG in Oregon and Washington (2050)......................18
Exhibit 19. Summary of Monte Carlo Simulation Results for RNG domestically(2030).......................................................18
Exhibit 20.Summary of Monte Carlo Simulation Results for RNG domestically(2050).....................................................19
Exhibit 21. LCA Boundary for RNG Supply Chain via Anaerobic Digestion....................................................................................20
Exhibit 22. RNG Carbon Intensity Projection Base Case Results (kgCO2e/ MMBtu)...............................................................22
Exhibit 23. Different Hydrogen Production Methods.....................................................................................................................................23
Exhibit 24. IRA Section 45V Clean Hydrogen Production Tax Credit for Qualified Facilities...........................................24
Exhibit 25. Sampled Proton Exchange Membrane (PEM) Electrolyzer Facility for Hydrogen Production..............25
Exhibit 26. Capacity Factor for Northwest U.S. and Average U.S..........................................................................................................26
Exhibit 27. Electrolyzer Facility Production Cost Inputs..............................................................................................................................26
Exhibit 28.45V Hydrogen Investment Tax Credit and Production Tax Credit...........................................................................29
Exhibit 29. Summary of Results for Hydrogen Produced from Solar, Wind and Nuclear...................................................30
Exhibit 30. Summary of Monte Carlo Simulation Results for Hydrogen Produced from Solar,Wind and Nuclear
(Oregon and Washington, 2050)...................................................................................................................................................................................31
Exhibit 31.ATR Facility Production Cost Inputs..................................................................................................................................................33
Exhibit 32. Summary of Results for Blue Hydrogen.........................................................................................................................................35
Exhibit 33.Summary of Monte Carlo Simulation Results for Blue Hydrogen (Oregon and Washington,the Year
2050)................................................................................................................................................................................................................................................36
Exhibit 34. Pyrolysis Facility Production Cost Inputs....................................................................................................................................37
Exhibit 35.Summary of Results for Turquoise Hydrogen...........................................................................................................................39
Exhibit 36. Summary of Monte Carlo Simulation Results for Turquoise Hydrogen - Plasma Pyrolysis (Oregon
andWashington,the Year 2050)................................................................................................................................................................................40
CONFIDENTIAL ii 2025 Natural Gas IRP Appendix 234

ICF Alternative Fuels Analysis - NW Natural,Avista, and Cascade IRP Support March 2025
Exhibit37. Hydrogen Pipeline Cost Summary......................................................................................................................................................41
Exhibit 38.Storage and Transport Assumptions for Hydrogen.............................................................................................................43
Exhibit 39. Biomass Resources Considered.........................................................................................................................................................44
Exhibit 40. List of Data Sources for RING Feedstock Inventory.............................................................................................................45
Exhibit 41. List of Data Sources for RING Feedstock Inventory...............................................................................................................45
Exhibit 42. Heating Values for Agricultural Residues....................................................................................................................................46
Exhibit43. Heating Values for Energy Crops.......................................................................................................................................................47
Exhibit 44. Synthetic Methane via Biomass Gasification Resource Potential Projection (OR &WA and
National).........................................................................................................................................................................................................................................49
Exhibit 45. Synthetic Methane via P2G Resource Potential Projection (OR &WA, million MMBtu/y)......................49
Exhibit 46. Synthetic Methane via P2G Resource Potential Projection (National, million MMBtu/y)........................50
Exhibit 47. ICF Synthetic Methane Assumptions.............................................................................................................................................50
Exhibit 48. Projected Methanation Cost Reductions ($/kW)....................................................................................................................51
Exhibit 49. Synthetic CH4 from Biomass Levelized Cost Projection Base Case Results ($/MMBtu).........................52
Exhibit 50. Summary of Monte Carlo Simulation Results for Synthetic CH4 from Biomass (2030)...........................52
Exhibit 51.Synthetic Methane paired with P2G Levelized Cost Projection Base Case Results (Oregon and
Washington, $/MMBtu).........................................................................................................................................................................................................52
Exhibit 52. Synthetic Methane paired with P2G Levelized Cost Projection Base Case Results (National,
$/MMBtu).......................................................................................................................................................................................................................................53
Exhibit 53.Summary of Monte Carlo Simulation Results for Synthetic CH4 from Methanation of Hydrogen
(2030)..............................................................................................................................................................................................................................................53
Exhibit 54. LCA Boundary for Synthetic Methane via Biomass Gasification................................................................................54
Exhibit 55. RING Carbon Intensity Projection Base Case Results (kgCO2e/ MMBtu)..............................................................54
Exhibit 56. Illustrative Flow of RIN Generation and Retirement.............................................................................................................57
Exhibit 57. Nested Categories of Renewable Fuels in the RFS Program..........................................................................................57
Exhibit 58. Determining Intrinsic RIN Value...........................................................................................................................................................58
Exhibit 59. Historical D3, D4, D5 and D6 RIN Pricing(nominal), 2016 to mid-2024...............................................................59
Exhibit 60. D4 RIN Pricing vs. BOHO Spread.......................................................................................................................................................60
Exhibit 61. ICF's RIN Price Forecast, Reference Case (nominal dollars)............................................................................................62
Exhibit 62. ICF's RIN Price Forecast, Downside Case(nominal dollars)...........................................................................................62
Exhibit 63. ICF Estimated Pricing Range for RTCs ($/mmBtu)................................................................................................................63
Exhibit 64.Options for CO2 Utilization (via NETL)...........................................................................................................................................64
Exhibit 65. CO2 Capture Cost from Industrial and Power Plant Flue Gas and Process Gas Streams.......................66
Exhibit 66. CO2 Compression, Dehydration,Transport, and Storage Costs as Estimated by GCCSI.......................66
Exhibit 67. Geologic Storage Capacity by State..............................................................................................................................................68
Exhibit68. CO2 Pipeline Costs........................................................................................................................................................................................70
Exhibit 69. CO2 Transport Costs, Pipeline versus Truck................................................................................................................................71
Exhibit 70.CCUS Cost for Base Case Assumptions (2030)....................................................................................................................72
Exhibit 71. CCUS Cost for Base Case Assumptions (2050)......................................................................................................................72
Exhibit 72. Histogram on CCUS Costs Size 400-800MMBtu/hr.for 2050...................................................................................72
Exhibit 73. GWP over 100-year Horizon Under ARS........................................................................................................................................74
CONFIDENTIAL iii 2025 Natural Gas IRP Appendix 235

7*ICF Alternative Fuels Analysis — NW Natural,Avista, and Cascade IRP Support March 2025
Exhibit 74. Electricity Generation Mix in the Pacific Region from 2022 to 2050.....................................................................74
Exhibit 75. Shares of Technologies for Other Power Plants in the Pacific Region from 2022 to 2050....................75
Exhibit 76. Electricity Carbon Intensities (gCO2e/kWh) in the Pacific Region from 2022 to 2050............................75
Exhibit 77. CH4 Leakage Rate for Each Stage in Conventional NG and Shale Gas Pathways...........................................76
Exhibit 78. Fossil Natural Gas Carbon Intensities (gCO2e/MMBtu, LHV)from 2022 to 2050.........................................76
Exhibit 79. Assumptions to estimate RNG carbon intensities................................................................................................................77
Exhibit 80. RING carbon intensities (gCO2e/MMBtu, LHV)from 2022 to 2050..........................................................................77
Exhibit 81.Applicable Stochastic Variables to Each Fuel Type.............................................................................................................80
Exhibit 82. Correlation Assumptions for Each Pair of Variables............................................................................................................82
CONFIDENTIAL iv 2025 Natural Gas IRP Appendix 236

Executive Summary
Overview
This report,commissioned by NW Natural,Avista Utilities, and Cascade Natural Gas Corporation
(collectively referred to as "the Utilities"), provides a detailed assessment of the levelized cost,
resource potential, and carbon intensity of renewable natural gas (RNG), hydrogen, synthetic
methane, and carbon capture and geologic storage (CCS) in Oregon and Washington.This analysis
supports the Utilities' Integrated Resource Plan (IRP) filings and informs their decision-making
processes.
Fuels Studied
• Renewable Natural Gas(RNG) is derived from biomass or other renewable resources and is a
pipeline-quality gas interchangeable with conventional natural gas.The study evaluates the
potential of RNG in contributing to a low-carbon energy future.
• Hydrogen, produced through various methods such as electrolysis, is assessed for its viability as
a clean fuel.The analysis considers the technical advancements and cost implications of using
hydrogen as a primary energy source.
• Synthetic methane, produced from two pathways:1)via biomass gasification and 2) methanation
of carbon dioxide and hydrogen produced via electrolysis and.These pathways offer another
pathway to a sustainable energy system.The report evaluates the respective production
processes and potential adoption.
• Carbon Capture, Use,and Storage(CCUS)technologies, essential for reducing emissions from
current fossil fuel use,are analyzed for their effectiveness in capturing CO2 and storing it
underground.The report highlights the technical and economic feasibility of implementing CCS in
the region.
Assessment Methodology
The assessment of carbon intensity for each low-carbon fuel and carbon capture/use/geologic
storage involved a detailed analysis using the Greenhouse gases, Regulated Emissions, and Energy
use in Technologies (GREET) model, developed by the Argonne National Laboratory(ANL).
The levelized cost of energy(LCOE)was also estimated for each resource to characterize lifetime
costs relative to lifetime energy production.
ICF's study methodology included:
• Evaluating the technical potential of each fuel based on feedstock availability and technological
advancements.
• Calculating the LCOE for each low-carbon fuel and the cost of carbon capture and storage.
• Conducting stochastic analysis to yield a distribution of probabilistic outcomes for supply
potential and LCOE, aiding the integrated resource planning process.
Key Findings
1. Renewable Natural Gas: RNG shows significant potential due to its compatibility with
existing natural gas infrastructure. However, its deployment is contingent on the availability
of biomass feedstocks and advancements in production technologies. Its cost might be best
CONFIDENTIAL 1 2025 Natural Gas IRP Appendix 237

considered compared to the cost of other decarbonization resources (i.e.,on a $/tonCO2e
basis)than to conventional natural gas prices.
2. Hydrogen: Hydrogen emerges as a promising clean fuel,especially with advancements in
electrolysis. Its scalability and integration into the energy system depend on cost reductions
and infrastructure development.
3. Synthetic Methane: While synthetic methane offers a sustainable energy solution, its
adoption is currently hindered by high production costs.Technological advancements and
policy support are crucial for its future viability.
4. Renewable Thermal Certificates: A market-based mechanism that enables market actors
to comply with state mandates and/or to fulfill their voluntary commitments, while
preventing the risk of double counting environmental benefits.These will be an important
mechanism to help build confidence in the import/export of gaseous low-carbon fuels like
RING, hydrogen,and synthetic methane.
5. Carbon Capture and Geologic Storage: CCS is a critical technology for mitigating emissions
from fossil fuels.While the components of CCS systems (acid gas recovery units,
compressors, pipeline, injection well) are mature technologies,the market for CCS services is
just emerging. ICF's assessment is that the market for CCS is not mature. ICF's assessment
indicates that CCS can be effectively implemented in the region, provided there is adequate
investment and regulatory support.
6. Carbon Intensity(Cl):A common theme for the low-carbon fuels of interest, as well as
geologic natural gas and the region's electricity mix, is that CI was projected to decrease
(improve) over time.This may be due to energy efficiency improvements in production
processes, lower-carbon electricity portfolio trends, etc.
7. Stochastic Analysis:The stochastic modeling exercise demonstrated a range of
probabilistic outcomes for the technical potential and LCOE of each low-carbon fuel.The
results underscore the importance of considering variability and uncertainty in planning and
decision-making.
This report ultimately provides a comprehensive analysis of low-carbon fuels and CCS, highlighting
their potential to contribute to a sustainable energy future in Oregon and Washington.The findings
support the Utilities'efforts to integrate these technologies into their IRP filings and advance their
clean energy goals.
CONFIDENTIAL 2 2025 Natural Gas IRP Appendix 238

Introduction
NW Natural, Avista Utilities,and Cascade Natural Gas Corporation (collectively referred to as "the
Utilities"throughout this report) contracted with ICF to develop forecasts for levelized cost,
technical potential, resource life, and carbon intensity and characterize the renewable thermal
credits (RTC) available for renewable natural gas (RING), hydrogen,synthetic methane, carbon
capture and geologic storage in Oregon and Washington.This report supports analyses that are
performed by the Utilities as part of their respective Integrated Resource Plan (IRP)filings.
Overview of ICF's Approach
ICF's analysis focused on the technical potential and levelized cost of energy(LCOE)for the low-
carbon fuels of interest.To do so, ICF assessed the carbon intensity of each fuel and utilized
stochastic analysis to yield a distribution of probabilistic outcomes of supply potential and LCOE
that can help inform the integrated resource planning process.
The methodology ICF used to calculate LCOE and technical potential for each low-carbon fuel of
interest is detailed in the sections that follow.The general methodology for the LCOE calculation is
provided in the Appendix. ICF's assessment of the technical potential of each low-carbon fuel is
linked to factors such as feedstock availability and technological advancements. For each relevant
section, ICF briefly discusses the status of Renewable Thermal Certificates or RTCs.
ICF also calculated the lifecycle carbon intensity of low-carbon fuels from the feedstocks and
production methods of interest using the Greenhouse gases, Regulated Emissions, and Energy use in
Technologies (GREET) model, developed by the Argonne National Laboratory(ANL).' GREET and
GREET-based models like OR-GREET used for the Oregon Clean Fuels Program are the industry
standard for analyzing the lifecycle carbon intensity of fuels in the United States.
The cost, resource, and carbon intensity analyses were combined into a stochastic modeling
exercise.These were used as modeling variables yield a distribution of probabilistic outcomes for
the study.
Argonne GREET Fuel Cycle Model (anl.gov)
CONFIDENTIAL 3 2025 Natural Gas IRP Appendix 239

Renewable Natural Gas
Resource Type
RNG is derived from biomass or other renewable resources and is a pipeline-quality gas that is fully
interchangeable with conventional natural gas.As a point of reference,the American Gas Association
(AGA) uses the following definition for RNG:
Pipeline compatible gaseous fuel derived from biogenic or other renewable sources that has
lower lifecycle carbon dioxide equivalent(CO2e) emissions than geological natural gas.'
The most common way to produce RNG today is via anaerobic digestion (AD),whereby
microorganisms break down organic material in an environment without oxygen.The four key
processes in anaerobic digestion are:
• Hydrolysis is the process whereby longer-chain organic polymers are broken down into shorter-
chain molecules like sugars, amino acids,and fatty acids that are available to other bacteria.
• Acidogenesis is the biological fermentation of the remaining components by bacteria,yielding
volatile fatty acids, ammonia,carbon dioxide, hydrogen sulfide,and other byproducts.
• Acetogenesis of the remaining simple molecules yields acetic acid, carbon dioxide,and hydrogen.
• Lastly,methanogens use the intermediate products from hydrolysis,acidogenesis, and
acetogenesis to produce methane, carbon dioxide, and water,where the majority of the biogas is
emitted from anaerobic digestion systems.
The process for RNG production generally takes place in a controlled environment, referred to as a
digester or reactor, including landfill gas facilities. When organic waste, biosolids,or livestock manure
is introduced to the digester,the material is broken down over time (e.g., days) by microorganisms,
and the gaseous products of that process contain a large fraction of methane and carbon dioxide.
The biogas requires capture and subsequent conditioning and upgrade before pipeline injection.The
conditioning and upgrading helps to remove any contaminants and other trace constituents,
including siloxanes,sulfides and nitrogen,which cannot be injected into common carrier pipelines,
and increases the heating value of the gas for injection.
RNG can be produced from a variety of renewable feedstocks, as described in the table below.
Exhibit 1. List of RNG Feedstocks
- - . Description
Animal manure Manure produced by livestock, including dairy cows, beef cattle,swine,
sheep, goats, poultry, and horses.
Food waste Commercial, industrial and institutional food waste, including from food
processors,grocery stores, cafeterias, and restaurants.
Landfill gas (LFG) The anaerobic digestion of organic waste in landfills produces a mix of
gases, including methane (40-60%).
'AGA, 2019. RNG: Opportunity for Innovation at Natural Gas Utilities,
https://pubs.naruc.org/pub/73453B6B-A25A-6AC4-BDFC-C709B202C819
CONFIDENTIAL 4 2025 Natural Gas IRP Appendix 240

- - • • Description
Water resource Wastewater consists of waste liquids and solids from household,
recovery commercial, and industrial water use; in the processing of wastewater,
facilities (WRRF) a sludge is produced,which serves as the feedstock for RNG.
Resource Potential
ICF used a mix of existing studies, government data, and industry resources to estimate the current
and future supply of the feedstocks.The table below summarizes some of the resources that ICF
drew from to complete our resource assessment, broken down by RNG feedstock:
Exhibit 2. List of Data Sources for RNG Feedstock Inventory
Feedstock - Resources - -
U.S. Environmental Protection Agency(EPA)AgStar Project
Animal manure Database
• U.S. Department of Agriculture (USDA) Census of Agriculture
•Food waste U.S. Department of Energy(DOE) Billion Ton Report
• Bioenergy Knowledge Discovery Framework (KDF)
• U.S. EPA Landfill Methane Outreach Program
LFG • Environmental Research & Education Foundation (EREF)
• U.S. EPA Clean Watersheds Needs Survey(CWNS)
WRRFs • Water Environment Federation
The sub-sections below characterize the resources considered in the RNG analysis. ICF primarily
drew from previous research conducted at the national and state levels'to characterize resource
availability. ICF distinguished between two geographies for the analysis: a)Oregon and Washington
and b) national. Note that the latter excludes the resources that are included in the former. ICF
assumed that the Utilities would have near-full access to resources identified for RNG development
in Oregon and Washington and a portion of the national-level resources considered.
More specifically, ICF assumed that the Utilities would have"first-mover access"to RNG from
domestic resources. ICF reviewed states that have robust policy frameworks in place to advance
RNG deployment in the state (but not necessarily exclusively within their state) and assumed that
NW Natural, Avista Utilities, and Cascade Natural Gas Corporation would have a population-weighted
share of first-mover access to national resources. ICF also included British Columbia and Quebec in
our consideration of first movers because these two Canadian provinces have robust RNG policies in
place and have already procured significant amounts of US-based RNG. ICF's assumption regarding
first mover access yields a result whereby the Utilities will likely be able to access up to about 13% of
'American Gas Foundation, Renewable Sources of Natural Gas, 2019.Available online at
https://gasfoundation.org/2019/12/18/renewable-sources-of-natural-gas/
CONFIDENTIAL 5 2025 Natural Gas IRP Appendix 241

the total domestic RNG production,which about 3.5-4 times greater than the simple population-
weighted share that one might otherwise assume.
Animal Manure
Animal manure as an RNG feedstock is produced from the manure generated by livestock, including
dairy cows, beef cattle,swine,sheep,goats, poultry, and horses.
The main components of anaerobic digestion of manure include manure collection,the digester,
effluent storage (e.g., a tank or lagoon), and gas handling equipment.There are a variety of livestock
manure processing systems that are employed at farms today, including plug-flow or mixed plug-
flow digesters,complete-mixed digesters, covered lagoons,fixed-film digesters,sequencing-batch
reactors, and induced-blanked digesters. Many dairy manure projects today use plug-flow or mixed
plug-flow digesters.
ICF considered animal manure from a variety of animal populations, including beef and dairy cows,
broiler chickens, layer chickens,turkeys, and swine.Animal populations were derived from the United
States Department of Agriculture's (USDA) National Agricultural Statistics Service. ICF used
information provided from the most recent census year(2017) and extracted total animal
populations on a county and state level.' ICF developed the maximum RNG potential using animal
manure production and the energy content of dried manure taken from a California Energy
Commission report prepared by the California Biomass Collaborative.'Concentrated animal feeding
operations (CAFOs) -farms/animal feeding operations with more than 1,000 animal "units" (defined
as 1,000 pounds live weight') - provide an indication of where RNG from animal manure could be
produced at significant scale.
Food Waste
Food waste includes biomass sources from commercial, industrial and institutional facilities,
including from food processors and manufacturers, grocery stores,cafeterias, and restaurants. Food
waste from residential sources is not reflected in this analysis but could be an additional resource
for food waste biomass with the implementation of effective waste diversion policies.
Food waste is a major component of municipal solid waste(MSW)—accounting for about 15% of
MSW streams. More than 75%of food waste is landfilled. Food waste can be diverted from landfills to
a composting or processing facility where it can be treated in an anaerobic digester. ICF limited our
consideration to the potential to utilize the food waste that is currently landfilled as a feedstock for
RNG production via AD,thereby excluding the 25%of food waste that is recycled or directed to
waste-to-energy facilities. In addition,food waste that is potentially diverted from landfills in the
'USDA, 2017. 2017 Census of Agriculture, https://www.nass.usda.gov/AgCensus/index.php
5 Williams, R. B., B. M.Jenkins and S. Kaffka (California Biomass Collaborative). 2015.An Assessment of
Biomass Resources in California, 2013 - DRAFT.Contractor Report to the California Energy
Commission. PIER Contract 500-11-020.Available online here.
6 This equates to 1000 head of beef cattle,700 dairy cows, 2500 swine weighing more than 55 Ibs,
125 thousand broiler chickens,or 82 thousand laying hens or pullets) confined on site for more than
45 days during the year."Via Natural Resources Conservation Service (U.S. Department of
Agriculture),
https://www.nres.usda.gov/wps/portal/nres/main/national/plantsanimals/livestock/afo/#:-:text=A%2
OCAFO%20is%20an%20AFO,confined%20on%20site%20for%20more
CONFIDENTIAL 6 2025 Natural Gas IRP Appendix 242

future is not included in the landfill gas analysis (outlined in more detail below), thereby avoiding any
issues around double counting of biomass from food waste.
As food waste is generated from population centers and typically diverted at waste transfer stations
rather than delivered to landfills, it is challenging to identify specific facilities or projects that will
generate RNG from food waste. However,food waste can potentially utilize existing or future AD
systems at landfills and water resource recovery facilities.
Landfill Gas
The Resource Conservation and Recovery Act of 1976 (RCRA,1976) sets criteria under which landfills
can accept municipal solid waste and nonhazardous industrial solid waste. Furthermore,the RCRA
prohibits open dumping of waste, and hazardous waste is managed from the time of its creation to
the time of its disposal. Landfill gas (LFG) is captured from the anaerobic digestion of biogenic waste
in landfills which produces a mix of gases, including methane,with a methane content generally
ranging 45%-60%.'The landfill itself acts as the digester tank—a closed volume that becomes
devoid of oxygen over time, leading to favorable conditions for certain micro-organisms to break
down biogenic materials.
The composition of the LFG is dependent on the materials in the landfill, among other factors, but is
typically made up of methane, carbon dioxide (CO2), nitrogen (1\12), hydrogen,CO, oxygen (02),
sulfides (e.g., hydrogen sulfide or H2S), ammonia,and trace elements like amines, sulfurous
compounds, and siloxanes.$ RING production from LFG requires advanced treatment and upgrading
of the biogas via removal of CO2, H2S, siloxanes, N2, and 02 to achieve a high-energy(Btu) content gas
for pipeline injection.The table below summarizes landfill gas constituents,the typical concentration
ranges in which they present in LFG, and commonly deployed upgrading technologies in use today.
Exhibit 3. Landfill Gas Constituents and Corresponding Upgrading Technologies
ConstituentLFG ical Concentration - . . •
y for Removal
Range
• High-selectivity membrane
separation
Carbon dioxide,COz 40% - 60% • Pressure swing adsorption (PSA)
systems
• Water scrubbing systems
• Amine scrubbing systems
• Solid chemical scavenging
Hydrogen sulfide, H2S 0 -1% • Liquid chemical scavenging
• Solvent adsorption
• Chemical oxidation-reduction
Siloxanes <0.1% • Non-regenerative adsorption
7 Biogas captured from dedicated anaerobic digesters tends to have a higher percent methane
content(-60%), especially compared to landfill gas.That said, upgrading technology for other types
of biogas is like that used for landfill gas.
8 Siloxane only exists in biogas from landfills and WRRF.
CONFIDENTIAL 7 2025 Natural Gas IRP Appendix 243

ConstituentLFG ical Concentration
- . . •
y for Removal
Range
• Regenerative adsorption
Nitrogen,N2 2%- 5% • PSA systems
Oxygen,02 0.1% - 1% • Catalytic removal (02 only)
To estimate the feedstock potential of LFG, ICF used outputs from the LandGEM model,which is an
automated tool with a Microsoft Excel interface developed by the U.S. EPA. ICF used LandGEM to
estimate the emissions rates for landfill gas and methane based on user inputs including waste-in-
place (WIP),facility location and climate conditions, and waste received per year.The LFG output
was estimated on a facility-by-facility basis.About 1,150 facilities report methane content;for the
facilities for which no data were reported, ICF assumed the median methane content of 49.6%. ICF
also extracted data from the Landfill Methane Outreach Program (LMOP) administered by the U.S.
EPA,which included more than 2,000 landfills.
Water Resource Recovery Facilities
Wastewater is created from residences and commercial or industrial facilities. It consists primarily of
waste liquids and solids from household water usage,from commercial water usage, or from
industrial processes. Depending on the architecture of the sewer system and local regulation, it may
also contain storm water from roofs, streets, or other runoff areas.The contents of the wastewater
may include anything which is expelled (legally or not)from a household and enters the drains. If
storm water is included in the wastewater sewer flow, it may also contain components collected
during runoff:soil, metals, organic compounds, animal waste,oils, and solid debris such as leaves and
branches.
Wastewater is processed and treated at dedicated facilities, including sewerage treatment plants
and wastewater treatment plants, covered by the umbrella term of "water resource recovery
facilities" (WRRFs). Processing of wastewater influent to a WRRF is comprised typically of four stages:
pre-treatment, primary,secondary,and tertiary treatments.These stages consist of mechanical,
biological,and sometimes chemical processing.
• Pre-treatment removes all the materials that can be easily collected from the raw
wastewater that may otherwise damage or clog pumps or piping used in treatment
processes.
• In the primary treatment stage,the wastewater flows into large tanks or settling bins,thereby
allowing sludge to settle while fats,oils,or greases rise to the surface.
• The secondary treatment stage is designed to degrade the biological content of the
wastewater and sludge and is typically done using water-borne micro-organisms in a
managed system.
• The tertiary treatment stage prepares the treated effluent for discharge into another
ecosystem, and often uses chemical or physical processes to disinfect the water.
The treated sludge from the WRRF can be landfilled, and during processing it can be treated via
anaerobic digestion,thereby producing methane which can be used for beneficial use with the
appropriate capture and conditioning systems put in place.
CONFIDENTIAL 8 2025 Natural Gas IRP Appendix 244

To estimate the amount of RNG produced from wastewater at WRRFs, ICF used data reported by the
U.S. EPA,'a study of WRRFs in New York State,10 and previous work published by AGF.11 ICF used an
average energy yield of 7.003 MMBtu/million gallons per day of wastewater flow.
RNG Resource Potential Projection
The following figures summarize the maximum RNG potential for each feedstock and production
technology in OR and WA and at the national level.
Exhibit 4. RNG Resource Potential Projection Base Case Results (million MMBtu/y) (OR& WA)
40
35
■AM ■FW ■LFG WRRF
30
a° � 25
� m
20
v �
3 0
o _ 15
a
Z v 10
ix
5
0 ■
2025 2030 2035 2040 2045 2050
' US EPA, Opportunities for Combined Heat and Power at Wastewater Treatment Facilities,October
2011.Available online here.
10 Wightman,J and Woodbury, P., Current and Potential Methane Production for Electricity and Heat
from New York State Wastewater Treatment Plants, New York State Water Resources Institute at
Cornell University. Available online here.
11 AGF,The Potential for Renewable Gas: Biogas Derived from Biomass Feedstocks and Upgraded to
Pipeline Quality, September 2011.
CONFIDENTIAL 9 2025 Natural Gas IRP Appendix 245

Exhibit 5. RNG Resource Potential Projection Base Case Results (million MMBtu/y) (National)12
200
175
■AM ■FW LFG WRRF
150
4
a 4J 125
m
v100
3 �
O
o = 75
a �
Z v 50
o:
25
0
2025 2030 2035 2040 2045 2050
RNG Levelized Cost
ICF developed assumptions for the capital expenditures and operational costs for RNG production
from the various feedstock and technology pairings outlined previously. ICF characterized costs
based on a series of assumptions regarding the production facility sizes (as measured by gas
throughput in units of standard cubic feet per minute [SCFMI),gas upgrading and conditioning and
upgrading costs (depending on the type of technology used, the contaminant loadings,etc.),
compression,and interconnect for pipeline injection.We also include operational costs for each
technology type.The table below outlines some of ICF's baseline assumptions that we employed in
our production cost modeling.
Exhibit 6. Illustrative ICF RNG Cost Assumptions
Cost Parameter � ICIF Cost Assumptions
Capital Costs
• Differentiate by feedstock and technology type: anaerobic digestion
Facility Sizing
and thermal gasification.
• Prioritize larger facilities to the extent feasible but driven by
resource estimate.
Gas Conditioning and Upgrade . Vary by feedstock type and technology required.
Compression • Capital costs for compressing the conditioned/upgraded gas for
pipeline injection.
12 Note that the volumes shown for the national resource are scaled. ICF's assumption regarding first
mover access yields a result whereby the Utilities will likely be able to access up to about 13% of the total
domestic RNG production.
CONFIDENTIAL 10 2025 Natural Gas IRP Appendix 246

• Cost Assumptions
O&M Costs
Operational • Costs for each equipment type—digesters, conditioning equipment,
Costs collection equipment,and compressors—as well as utility charges for
estimated electricity consumption.
• The costs of delivering the same volumes of biogas that require
Delivery pipeline construction greater than 1 mile will increase,depending on
feedstock/technology type,with a typical range of$1-$5/MMBtu.
Levelized Cost of Gas
• Calculated based on the initial capital costs in Year 1, annual
Project Lifetimes operational costs discounted, and RNG production discounted
accordingly over a 20-year project lifetime.
ICF presents the costs used in our analysis as well as the levelized cost of energy(LCOE)for RNG in
different end uses.The LCOE is a measure of the average net present cost of RNG production for a
facility over its anticipated lifetime.The LCOE enables us to compare RNG feedstocks and other
energy types on a consistent per unit energy basis.The LCOE can also be considered the average
revenue per unit of RNG (or energy) produced that would be required to recover the costs of
constructing and operating the facility during an assumed lifetime.The LCOE calculated as the
discounted costs over the lifetime of an energy producing facility(e.g., RNG production) divided by a
discounted sum of the actual energy amounts produced.The LCOE is calculated using the following
formula:
-n It +Mt +Ft
` (1 +r)t
LCOE _
E t
t 1(1 +r)t
where It is the capital cost expenditures (or investment expenditures) in year t, Mt represents the
operations and maintenance expenses in year t, Ft represents the feedstock costs in year t (where
appropriate), Et represents the energy(i.e., RNG) produced in year t, r is the discount rate, and n is
the expected lifetime of the production facility.
ICF notes that our cost estimates are not intended to replicate a developer's estimate when
deploying a project. For instance, ICF recognizes that the cost category"gas conditioning and
upgrading" actually represents an array of decisions that a project developer would have to make
with respect to CO2 removal, H2S removal, siloxane removal, N2/O2 rejection,deployment of a thermal
oxidizer, among other elements.
In addition,the cost assumptions attempt to strike a balance between existing or near-term capital
and operational expenditures, and the potential for project efficiencies and associated cost
reductions that may eventuate over time as the RNG industry expands. For example, in general
construction and engineering costs may decline from present levels driven by the development and
implementation of modular technology systems or facilities.
These cost estimates also do not reflect the potential value of the environmental attributes
associated with RNG, nor the current markets and policies that provide credit for these
environmental attributes.
CONFIDENTIAL 11 2025 Natural Gas IRP Appendix 247

Furthermore,we understand that project developers have reported a wide range of interconnection
costs,with numbers as low as $200,000 reported in some states, and as high as $9 million in other
states.We appreciate the variance between projects, including those that use anaerobic digestion or
thermal gasification technologies, and our supply-cost curves are meant to be illustrative, rather
than deterministic.This is especially true of our outlook to 2050—we have not included significant
cost reductions that might occur as a result of a rapidly growing RING market or sought to capture
potential technological breakthroughs. For anaerobic digestion systems we have focused on projects
that have reasonable scale, representative capital expenditures,and reasonable operations and
maintenance estimates.
To some extent, ICF's cost modeling does presume changes in the underlying structure of project
financing,which is currently linked inextricably to revenue sharing associated with environmental
commodities in the federal Renewable Fuel Standard (RFS) market and California's Low Carbon Fuel
Standard (LCFS) market. Our project financing assumptions likely have a lower return than investors
may be expecting in the market today; however,our cost assessment seeks to represent a more
mature market to the extent feasible,whereby upward of 1,000-4,500 trillion Btu per year of RING is
being produced. In that regard,we implicitly assume that contractual arrangements are likely
considerably different and local/regional challenges with respect to RING pipeline injection have been
overcome.
Animal Manure
ICF developed assumptions for the region by distinguishing between animal manure projects, based
on a combination of the size of the farms and assumptions that certain areas would need to
aggregate or cluster resources to achieve the economies of scale necessary to warrant an RING
project.There is some uncertainty associated with this approach because an explicit geospatial
analysis was not conducted; however, ICF did account for considerable costs in the operational
budget for each facility assuming that aggregating animal manure would potentially be expensive.
Exhibit 7 includes the main assumptions used to estimate the cost of producing RING from animal
manure,while Exhibit 8 that follows provides example cost inputs for low cost and high animal
manure facilities.
Exhibit 7. Cost Consideration in LCOE Analysis for RNG from Animal Manure
Cost Elements
Performance 0 Capacity factor 0 92%
Installation Construction /
Costs Engineering • 40%of installed equipment costs
• Owner's cost
• $2.3 to $7.0 million,depending on
CO2 separation facility
Gas
• H2S removal $0.3 to $1.0 million, depending on
Upgrading N2/O2 removal facility
• $1.0 to $2.5 million, depending on
facility
• Electricity: 35
Utility Costs kWh/MMBtu o State-based average OR national
• Natural Gas: 35/0 of average
product
CONFIDENTIAL 12 2025 Natural Gas IRP Appendix 248

Cost Elements Considered
• 1 FTE for maintenance • 20% of installed capital costs -
O&M Miscellaneous conditioning/upgrade
• 10%of installed capital costs - digester
• Interconnect 0 $1.5 million
For Injection 0 Pipeline • $2 million
• Compressor 0 $0.140.5 million
Other • Value of digestate • Valued for dairy at about $100/cow/y
• Tipping fee 0 Excluded from analysis
Exhibit 8. Example Facility-Level Cost Inputs for RNG from Animal Manure
• •
Facility size(cows) High
1,300 4,000
Biogas production (SCFM) 90 265
Capital: collection $2.2m $4.8m
Capital: conditioning(CO2/O2 removal) $1.Om $1.8m
Capital: sulfur treatment $0.1m $0.2m
Capital: nitrogen rejection $0.3m $0.5m
Capital: compressor $0.1m $0.2m
Capital: pipeline(on-site) $2.Om $2.Om
Capital: utility interconnect $1.5m $1.5m
O&M:electricity and natural gas $0.2m $0.7m
Construction and engineering: installation $0.9m $1.1m
Construction and engineering:owner's cost $0.4m $0.5m
Food Waste
ICF made the simplifying assumption that food waste processing facilities would be purpose-built
and be capable of processing 60,000 tons of waste per year. ICF estimates that these facilities
would produce about 500 SCFM of biogas for conditioning and upgrading before pipeline injection.
In addition to the other costs included in other anaerobic digestion systems, we also included
assumptions about the cost of collecting food waste and processing it accordingly(see Exhibit 9).
Exhibit 10 that follows provides example cost inputs for low cost and high food waste facilities.
Exhibit 9. Cost Consideration in LCOE Analysis for RNG from Food Waste Digesters
Cost Elements Considered
Performance Capacity factor 0 92%
• Processing capability 0 30,000 to 120,000 tons per year
Dedicated • Organics processing • Varies by facility size
Equipment 0 Digester Varies by facility size
Installation • Construction/ . 30%of installed equipment costs
Costs Engineering 15%of installed equipment costs
• Owner's cost
• CO2 separation • $2.3 to $7.0 million, depending on facility
Gas Upgrading • H2S removal $0.3 million
• N2/O2 removal $1.0 million
CONFIDENTIAL 13 2025 Natural Gas IRP Appendix 249

Cost Elements
Electricity: 35
UtilityCosts kWh/MMBtu
Natural Gas: 20% of State-based average or national average
product
Operations & a 1.5 FTE for maintenance
• 20% of installed capital costs -
Maintenance 0 Miscellany conditioning/upgrade
• 10%of installed capital costs - digester
Other I Tipping fees • State based average($71-$80/ton)
• Interconnect • $1.5 million
For Injection • Pipeline • $2 million
• Compressor 0 $0.1-$0.325 million
Exhibit 10. Example Facility-Level Cost Inputs for RNG from Food Waste
High LCOE Low LCOE
Food waste processed (ton/y) 30,000 120,000
Biogas production (SCFM) 250 1,000
Capital: organics processing $7.Om $12.5m
Capital: digester $7.2m $19.2m
Capital: collection $0.2m $0.4m
Capital: conditioning(CO2/O2 removal) $1.4m $3.8m
Capital: sulfur treatment $0.1m $0.5m
Capital: nitrogen rejection $0.3m $2.5m
Capital: compressor $0.1m $0.3m
Capital: pipeline(on-site) $2.Om $2.Om
Capital: utility interconnect $1.5m $1.5m
O&M:electricity and natural gas $0.7m $4.8m
Construction and engineering: installation $1.2m $2.7m
Construction and engineering:owner's cost $0.6m $1.4m
Landfill Gas
ICF developed assumptions by distinguishing between four types of landfills: candidate landfills13
without collection systems in place, candidate landfills with collection systems in place, landfills14
without collection systems in place, and landfills with collections systems in place.15 ICF further
characterized the number of landfills across these four types of landfills, distinguishing facilities by
estimated biogas throughput (reported in units of SUM of biogas).
13 The EPA characterizes candidate landfills as one that is accepting waste or has been closed for five
years or less, has at least one million tons of WIP, and does not have an operational, under-
construction, or planned project. Candidate landfills can also be designated based on actual interest
by the site.
4 Excluding those that are designated as candidate landfills.
5 Landfills that are currently producing RNG for pipeline injection are included here.
CONFIDENTIAL 14 2025 Natural Gas IRP Appendix 250

For utility costs, ICF assumed 25 kWh per MMBtu of RNG injected and 6% of geological or fossil
natural gas used in processing. Electricity costs and delivered natural gas costs were reflective of
industrial rates reported at the state level by the EIA.
Exhibit 11 summarizes the key parameters that ICF employed in our cost analysis of LFG, while Exhibit
12 that follows provides example cost inputs for low-cost and high LFG facilities.
Exhibit 11. Cost Consideration in LCOE Analysis for RNG from Landfill Gas
Cost Elements Considered
Performance • Capacity factor . 92%
• Facility size • Varies
Installation • Construction / Engineering • 30% of installed equipment costs
Costs Owner's cost • 15%of installed equipment costs
• CO2 separation • $2.3 to $7.0 million, depending on facility
Gas Upgrading • H2S removal 0 $0.3 to $1.0 million, depending on facility
• N2/O2 removal • $1.0 to $2.5 million,depending on facility
• Electricity: 35 kWh/MMBtu • State-based average OR national
Utility Costs l o a
Natural Gas: 6/0 of product average
Operations& 0 1 FTE for maintenance 20%of installed capital costs -
Maintenance • Miscellany conditioning/upgrade
• 10%of installed capital costs - digester
• Interconnect • $1.5 million
For Injection . Pipeline 0 $2 million
• Compressor 0 $0.1-$0.5 million
Exhibit 12. Example Facility-Level Cost Inputs for RNG from LFG
• •
Biogas production (SCFM) .786 11,766
Capital:collection $0.6m $3.3m
Capital:conditioning(CO2/O2 removal) $2.3m $7.Om
Capital:sulfur treatment $0.2m $1.Om
Capital: nitrogen rejection $1.Om $2.5m
Capital:compressor $0.2m $0.5m
Capital: pipeline(on-site) $2.Om $2.Om
Capital: utility interconnect $1.5m $1.5m
O&M:electricity and natural gas $1.3m $20.Om
Construction and engineering: installation $1.7m $3.9m
Construction and engineering: owner's cost $0.9m $1.9m
Water Resource Recovery Facilities
ICF developed assumptions by distinguishing between WRRFs based on the throughput of the
facilities. The table below includes the main assumptions used to estimate the cost of producing
RNG at WRRFs while the table that follows provides example cost inputs for low cost and high WRRF
facilities.
CONFIDENTIAL 15 2025 Natural Gas IRP Appendix 251

Exhibit 13. Cost Consideration in LCOE Analysis for RNG from WRRFs
Cost Elements Considered P
Performance ' Capacity factor • 92%
• Facility size Varies
Installation . Construction / Engineering • 30% of installed equipment costs
Costs • Owner's cost • 15%of installed equipment costs
• CO2 separation $2.3 to$7.0 million,depending on facility
Gas Upgrading • H2S removal • $0.3 to $1.0 million, depending on facility
• N2/02 removal $1.0 to $2.5 million, depending on facility
U ilit
y Costs • Electricity: 26 kWh/MMBtu State-based average OR national average
t • Natural Gas:6%of product
Operations & 0 1 FTE for maintenance 20%of installed capital costs -
conditioning/upgrade
Maintenance 0 Miscellany • 10%of installed capital costs - digester
• Interconnect 0 $1.5 million
For Injection • Pipeline • $2 million
• Compressor • $0.1-$0.5 million
Exhibit 14. Example Facility-Level Cost Inputs for RNG from WRRFs
Biogas production (SCFM) .590 1,562
Capital:collection $0.6m $1.9m
Capital:conditioning(CO2/02 removal) $3.Om $3.8m
Capital:sulfur treatment $0.2m $0.5m
Capital: nitrogen rejection $1.Om $2.5m
Capital:compressor $0.2m $0.3m
Capital: pipeline(on-site) $2.Om $2.Om
Capital: utility interconnect $1.5m $1.5m
O&M:electricity and natural gas $1.Om $2.6m
Construction and engineering: installation $1.9m $2.7m
Construction and engineering: owner's cost $1.Om $1.4m
RNG Levelized Cost Resultp
The following figures and tables summarize the maximum RNG LCOE for each feedstock and
production technology in OR and WA and at the national level. ICF assumed the investment tax
credit (ITC)for RNG production (via the Qualified Biogas Property provisions) is available and
extended through 2030.
CONFIDENTIAL 16 2025 Natural Gas IRP Appendix 252

Exhibit 15. RNG Levelized Cost Projection Base Case Results (Oregon and Washington, $/MMBtu)
RNG Feedstock
• •
Animal Manure $35-$119 $50-$172
Food Waste $42-$81 $61-$119
Landfill Gas $7-$30 $10-$42
Water Resource Recovery Facilities $10-$44 $12-$59
Exhibit 16. RNG Levelized Cost Projection Base Case Results (National, $/MMBtu)
RNG Feedstock
• •
Animal Manure $36-$120 $51-$172
Food Waste $43-$83 $62-$120
Landfill Gas $8-$31 $10-$43
Water Resource Recovery Facilities $11-$45 $13-$60
The impact of the Monte Carlo process on costs for RNG in Oregon and Washington and nationally
are shown in the figures below for 2030 and 2050, respectively.The histograms depict the number
of the 1,000 Monte Carlo cases (y-axis)that fall within various cost ranges/technical potential ranges
(x-axis)for RNG from each of the feedstocks considered for Oregon and Washington and the United
States.
Exhibit 17. Summary of Monte Carlo Simulation Results for RNG in Oregon and Washington (2030)
2500
■ LCOG of RNG,OR&WA,2030
2000
1500
1000
500 � _II_ _ III I■ _III_ .�I�. _�IIII�■_ _■1���■._
0
r\ � O 0 N 00 L r` 10 Q GO N W L r` CO M 0 N 00 '1 7 r` CO 0 0 N 00 � p I-
O 00 F4 N N M Cl) CO 00 0�0 O) 0') 07 O O O N a7 N N
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4 � N M O ooao0orn0) OMr, O oo
CONFIDENTIAL 17 2025 Natural Gas IRP Appendix 253

Exhibit 18. Summary of Monte Carlo Simulation Results for RNG in Oregon and Washington (2050)
2000
1800 ■ LCOG of RNG,OR&WA,2050
1600
1400
1200
1000
800
600
20o I I� ■ �I_ _.� �� .__..I�II�I.._ -i
0
CV 00 M M O 0 C4 N r\ M 00 � d7 � Q CO r\ N 0o M M � O U M N (+')
.69
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of p co r; oo Cl? p (ri co r i n ri ao 6j (ri O co n N oo ? rn
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619,4 M� 69 6699 6699 � � 69 0 O b9 ifl N'69M � 4 � co � n a0 0
69
Exhibit 19. Summary of Monte Carlo Simulation Results for RNG domestically(2030)
2000
1800 ■ LCOG of RNG,National,2030
1600
1400
1200
1000
800
600
400
2000 ■ .� L _IIII_ _I�I�■_ _.1���1._
N r\ N r` — 0 — M — M — (D p g Q q Q q Q q M � M � M � M � M M 00 M 0o
r` O (V (2 r\ O (N Lo r\ O N Lo r` 0 N 0 r` 0 N Lo I- M (V -1 r` M N 'It r\ M N Iz:t r` M
b9Ef3 {A rZ co co w co
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(+') 00 (rj CO M 00 M 00 N r` N r` (V (V r O O O L O
CONFIDENTIAL 18 2025 Natural Gas IRP Appendix 254

Exhibit 20. Summary of Monte Carlo Simulation Results for RNG domestically(2050)
1800
■ LCOG of RNG,National,2050
1600
1400
1200
1000
800
600
400
2000 --- ------------------------------
" p M n M It N — M W M 'T M O (p q Ln M N Q M r, Ln — M r� (O q M
M n Q
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6q H4 Er4 64 69
co 0_ 00 ( Ch O CD LC� CV Q r` LS) (V Q 0) r- O CV (o LC) M O OD
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Ln CA (.0 O 4 Cb 3 L) 0-) M C N CD O o)N r- 69 OD L) L9 O M co
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RNG GHG Life Cycle Emissions
ICF evaluated life cycle carbon intensities (Cls)from the RNG feedstocks and production methods of
interest identified in Section 0. Specifically, ICF used life cycle assessment (LCA) methodology to
calculate the GHG emissions derived from all stages of the RNG production process up to the end
use combustion of the final product.This is defined as a cradle-to-grave LCA. Carbon intensity is
then quantified in terms of kgCO2e/MMBtu of RNG. Cradle-to-grave differs in system boundary from
other LCA methodologies such as the cradle-to-gate framework, in which accounting stops at the
end of the production process and prior to end use. Further, it is worth noting that, in the context of
this report, LCA refers only to the accounting of GHG emissions for within each stage of the RNG
cradle-to-grave process, whereas in other contexts an environmental LCA may refer to complete
accounting of all environmental impacts including,for example,water usage or impact assessment of
pollutants,etc.
RNG production from biogenic sources requires a series of steps (see Exhibit 21): collection of a
feedstock,delivery to a processing facility for biomass-to-gas conversion, gas conditioning,
compression and injection into the pipeline and combustion at the end use.
CONFIDENTIAL 19 2025 Natural Gas IRP Appendix 255

Exhibit 21. LCA Boundary for RNG Supply Chain via Anaerobic Digestion
Lifecycle GHG Emissions Accounting
Combustion GHG Emissions Accounting
+Feed�ock Collection +Digestion&Gas Processing +Transmission +Combustion
RNG —�
000❑
® 000
Liquids
Digestate
Solids
-Avoided Emissions
Collection&Processing Transmission End-Uses
Exhibit 21 shows how life cycle GHG emissions from RNG are generated along the three key stages of
the RNG supply chain.
• Aroductir Energy use required to collect feedstock material and then produce and
process RNG by way of digestion and processing for anaerobic digesters and landfills, or
synthetic gas (syngas) processing as it relates to thermal gasification. Sometimes, RNG
production is also credited for avoiding emissions (like methane)that would otherwise have
been released in the feedstock's business-as-usual management practices.
• Pineline transmission and distribution (T&D' Methane leaks primarily during transmission.
Methane leaks can occur at all stages in the supply chain from production through use but
are generally focused on leakage during transmission.
• ICF limits our explicit consideration to leaks of methane as those that occur during
transmission through a natural gas pipeline, as other methane losses that occur
during RNG production are captured as part of efficiency assumptions. The life cycle
carbon intensity calculations generated for this study include assumptions for
natural gas pipeline leaks synthesized by Argonne National Laboratory based on best
available data from scholarly work and the U.S. EPA. One key area of criticism of the
gas industry is that CH4 leaks are underreported.That said, utilities are focusing their
attention on driving down leaks on their systems.The potential for gas utilities and
RNG project developers to reduce the T&D and other methane leaks assumed here
could improve upon the estimated carbon emissions intensities estimated in this
report.
• End-use: RNG combustion.The GHG emissions attributable to RNG combustion are
straightforward: CO2 emissions from the combustion of biogenic renewable fuels are
CONFIDENTIAL 20 2025 Natural Gas IRP Appendix 256

considered zero, or carbon neutral. In other words,the GHG emissions from combustion are
limited to CH4 and N2O emissions because the CO2 emissions are considered biogenic.16
For fuel users and providers trying to reduce combustion GHG emissions, RNG is an attractive
prospect. Some entities report only on a combustion emissions accounting basis or report these
downstream emissions separately(gas combustion is generally Scope 3 for gas utilities)from their
other GHG tracking on Scope 1 and 2 GHGs. Depending on reporting protocol (voluntary or
regulatory, and even between regulatory incentive structures and governing bodies),there are a
variety of approaches taken to greenhouse gas emissions accounting.As policies develop federally
and across the northwest,the Utilities will need to navigate these reporting protocols and can inform
decision-making on the policy frameworks that will drive meaningful decarbonization in the energy
sector.
Argonne National Laboratory's GREET Model
In this study, LCAs were conducted using R&D GREETI_2023,the latest GREET model version
released by Argonne National Laboratory(ANL),to estimate the carbon intensity of RNG. Emission
factors for different processes are obtained from GREET as well.The GREET model is widely
recognized as a reliable tool for life cycle analysis — also known for transportation applications as
well-to-wheels (WTW) analysis — of transportation fuels and has been used by several regulatory
agencies (e.g., U.S. Environmental Protection Agency for the Renewable Fuel Standard and the LCFS)
for evaluation of various fuels.
GREET RNG LCA Modeling Approach and Model Modifications
ICF largely relied on GREET default values with adjustments to RNG transmission and distribution
distance, simulation year, Global Warming Potential (GWP) and grid electricity mix inputs to
accommodate various sensitivity scenarios. Consumption rate of fossil NG and grid electricity for
RNG pathways was adjusted to align with cost analysis values.
For WRRF,the baseline scenario ("Waste"tab)was adjusted to ensure the heating energy source for
the existing AD is the same as under the RNG pathway.
RNG GHG Life Cycle Emission Projection
The table below summarize the RNG GHG life cycle emissions for each feedstock for RNG production
in OR and WA and at the national level. ICF notes that the Cl values change slightly over time in the
analysis as a function of assumptions around decreases in a) the carbon intensity of electricity tied
to deployment of renewable energy and b) slight reductions in the carbon intensity of gas extraction
and distribution.
16 Intergovernmental Panel on Climate Change (IPCC) guidelines state that CO2 emissions from
biogenic fuel sources (e.g., biogas or biomass based RNG) should not be included when accounting
for emissions in combustion — only CH4 and N2O are included.This is to avoid any upstream "double
counting" of CO2 emissions that occur in the agricultural or land use sectors per IPCC guidance.
CONFIDENTIAL 21 2025 Natural Gas IRP Appendix 257

Exhibit 22. RNG Carbon Intensity Projection Base Case Results (kgCO2el MMBtu)
FeedstockRNG
Animal Manure -212.24 -202.75
Food Waste -71.94 -62.45
Landfill Gas 14.08 23.56
WRRFs 14.54 26.74
CONFIDENTIAL 22 2025 Natural Gas IRP Appendix 258

Hydrogen
Types of Hydrogen
ICF notes that in the last number of years, hydrogen production technologies have been assigned
colors to differentiate between various feedstock sources and production technologies like steam
methane reforming(SMR) or autothermal reforming(ATR) or electrolysis,to name a few.The industry
is moving away from these color descriptions in favor of carbon intensity metrics,the most popular
of which is kilograms of CO2 equivalent per kilogram of hydrogen (kg CO2e/kg H2).The different
methods of hydrogen production are identified as different colors of hydrogen and are shown in the
table below.
Exhibit 23. Different Hydrogen Production Methods
ProductionHydrogen Te
chnology
Feedstock JML.
Hydrogen produced from SMR, no carbon
Natural Gas 10 — 14 Gray
capture
Hydrogen produced from coal
Coal 20 — 30 Brown
gasification
Hydrogen produced from SMR/ATR with
Natural Gas 1.8 — 2.6 Blue
97%+ CCS
Hydrogen produced from SMR/ATR with
Natural Gas & RNG 0 — 0.45 Blue
97%+ CCS
Hydrogen produced from methane
RNG pyrolysis <0 Turquoise
Hydrogen produced from methane
Natural Gas <2.5 Turquoise
pyrolysis
Renewable Hydrogen produced via electrolysis from 18
Electricity renewable energy" 0 — 2.6 Green
Hydrogen produced via electrolysis from
Nuclear Energy <1 Pink
nuclear energy
Several governing bodies have begun to define"Clean Hydrogen" according to its carbon intensity.
In the US, the definition of Clean Hydrogen was established to be less than 4 kg CO2e/kg H2 under the
Bipartisan Infrastructure Law, and further defined by categories under the Inflation Reduction Act
(IRA)which created a new hydrogen production tax credit under Section 45V of the tax code. Only
projects that can demonstrate life cycle GHG emissions of less than 4kg CO2e/kg H2 produced are to
qualify, as demonstrated in the figure below. The emission ranges shown in the figure below are for
"The Green Hydrogen Coalition also considers hydrogen produced from steam biomethane
reforming and biomass gasification as green hydrogen. Source: https://www.ghcoalition.org/green-
hydrogen
'$ May vary depending on energy attribute certificates for grid tied facilities and the temporal
matching requirements.
CONFIDENTIAL 23 2025 Natural Gas IRP Appendix 259

Qualified facilities,which are to be required to meet certain wage and apprenticeship requirements
as defined in the IRA.
Exhibit 24. IRA Section 45V Clean Hydrogen Production Tax Credit for Qualified Facilities
IRA Section 45V
LCA Requirements
4.5 40.00
4 3S.00
3.5
30.00
N
3 =
2 25.00
of
2.5
ai 20.00
O 2 - v
U
00 15.00 O
Y 1.5 — D
Y
1 _ 10.00
0.5 5.00
0 __owl 0.00
$0.60 $0.75 $1.00 $3.00
Credit Value($/kg 1-12)
In this analysis, ICF primarily focused on supply from PEM Electrolysis using renewable energy for
green and pink hydrogen,ATR with CCS for blue hydrogen,and both thermal and catalytic pyrolysis
for turquoise hydrogen. For blue and turquoise models, ICF used a blend of renewable natural gas
and conventional gas to optimize the tax credits.
Green and Pink Hydrogen (Electrolyzer)
Levelized Cost of Hydrogen
ICF has developed hydrogen production cost models for hydrogen produced using renewable and
nuclear energy and electrolyzer technology.
An electrolyzer facility includes the electrolyzer system along with the mechanical and electrical
balance of plant(BoP).The electrolyzer requires deionized water and typical equipment
manufacturers include a water treatment and recirculation system as part of the mechanical BoP.
Once the deionized water feeds into the electrolyzer,the electrolyzer splits the water into hydrogen
and oxygen. Oxygen and hydrogen are then treated to be separated from water.The oxygen could
be captured and sold or vented out into the atmosphere.The hydrogen goes through dryers to
remove moisture and is collected or compressed as a product.The electrical BoP consists of a
transformer and rectifier used to convert AC to DC voltage. The figure below shows the typical
electrolyzer and BoP equipment and the block flow diagram to produce hydrogen.19
11 Analysis of Advanced Hydrogen Production and Delivery Pathways (energy.gov)
CONFIDENTIAL 24 2025 Natural Gas IRP Appendix 260

Exhibit 25. Sampled Proton Exchange Membrane (PEM) Electrolyzer Facility for Hydrogen
Production21
r- - - - - - - - - - - - ------- - - - - - - - - - - - - - - - - --- - -,
� 1
Adsorbent Bed Dryer Hz
1 Deionizer --- 1
1 1
H,0 _ HOC
1 Charcoal Bed Filter Gas I
1 Separator/Condenser
1 Deionizer Clean u Pump I
XX 1
1 I
, 1
- - - - - - - - - - - - - - - - - - 1
1 �
1 Water Tank I Mechanical BoP Module
I Circulation Pump &0,Separator I
1 I
I I + -
I I
I I
1 1
1 I Legend (showing color coding►
1 I
1 1 �
1 I (I If ' i Electncal
1 I OJH,0 Mix
1 I Transformer
Water Cooled Chiller i Electrical Subsystem
l_
The cost of renewable hydrogen produced via electrolysis is highly dependent on the cost of the
electrolyzer units,the utilization of the electrolyzer units, and the price of electricity used in
production. Currently, electrolysis is more expensive than renewable hydrogen from SMR/ATR units.
Electrolysis for hydrogen production is a mature technology, but historical production to date has
only been at small scale for specific applications such as to produce oxygen on submarines, with
companies producing hydrogen for fuels such as Plug Power only emerging recently. Capacity
deployment is estimated to increase from approximately 40 megawatts (MW) of PEM capacity in
2022 to over 3,000 gigawatts (GW) in 2050 by some estimates.The potential for"numbering up"
architecture of including multiple electrolyzer stacks within a larger electrolyzer house is expected to
drive significant per-unit cost reductions in the future. These cost reductions are typically modeled
using"learning rates"which are calculated by determining the capital cost reduction for each
doubling of capacity. It is also expected that economies of scale and learning efficiencies from the
equipment manufactures as the technology develops could also decrease costs.
Production Cost Estimate Overview
ICF assumes that renewable costs are procured for hydrogen at the levelized cost of energy.The
LCOE represents the minimum price a renewable resource must earn to recover all costs and
provide the required rate of return to its investors. U.S. Energy Information Administration (EIA)
Annual Energy Outlook (AEO) costs were used to develop LCOEs for wind and solar power and ICF
developed costs for nuclear using NREL's technology data.21 ICF used a Monte Carlo analysis for the
20 Analysis of Advanced Hydrogen Production and Delivery Pathways (energy.gov)
21 Nuclear I Electricity 12024 1 ATB I NREL
CONFIDENTIAL 25 2025 Natural Gas IRP Appendix 261

renewable energy credit(RECs) pricing by assuming a varying premium percentage for the LCOE.
The RECs pricing is dependent on the additional costs associated with Section 45V requirements for
the Energy Attribute Credits (EAC) such as hourly matching of the renewable energy source to every
hour of hydrogen production, etc. ICF also assumed capacity factor(CF) on a regional and national
basis using data from EIA22 as shown in Exhibit 26.
Exhibit 26. Capacity Factor for Northwest U.S. and Average U.S.
Capacity Factor- EIA,2022
-
Oregon 23.9% 23.7%
Washington 14.8% 27.3%
92%
Average Regional 19.4% 25.5%
Average National 24.4% 35.9%
ICF analysis was prepared assuming 3%annual maintenance as a percentage of capex and uses an
electrolyzer cost of $1050/kW based on average bid prices from recent projects which we are
familiar and a total installed cost (TIC)factor range of 2X to 2.7X the electrolyzer cost for greenfield,
grid connected electrolyzer plants with which we are familiar.The levelized cost of hydrogen
projection is based on a 220 MW electrolyzer facility with a learning curve rate of 22% and a water
cost of$5.63/kgal and is assumed with an annual escalation of approximately 1%.23 The electrolyzer
stack membranes are assumed to be replaced every 7-10 years;this is included in ICF's assumptions
by accounting for as a major maintenance cost of 30% of the direct capex, the cost for which is
allocated evenly as an annualized cost.The labor cost for this specific analysis was assumed to be
approximately $2MM USD annually, however labor costs are subject to regional differences. Based
on electrolyzer experience in other analog industries such as the chlor-alkali business,continuous
deionization and reverse osmosis systems used to produce clean water, and academic studies24 it is
our expectation that industrial PEM electrolyzer maintenance will require between 3-5% of capex on
an annual basis for preventative and corrective maintenance. Preventative and corrective
maintenance components include but are not limited to cleaning of contamination or impurities
within PEM system,and regular maintenance for the water treatment system, compressor, hydrogen
dryer and other BoP components.The cost includes electrolyzer membrane stack replacement,
which is funded as a major maintenance item.
Exhibit 27. Electrolyzer Facility Production Cost Inputs
Input Value Comments
Sample Facility Size
Electrolyzer Size 220 MW Based on projects with which ICF is
familiar
Annual Production 20,000,000 kg Based on projects with which ICF is
Target familiar
Energy and Water Inputs
22 https://www.eia.gov/state/seds/data.php?incfile=/state/seds/sep_fuel/html/fuel_cf.html&sid=WA
23 https://www.osti.gov/servlets/purl/1975260
24 Optimized electrolyzer operation: Employing forecasts of wind energy availability, hydrogen
demand,and electricity_prices - ScienceDirect
CONFIDENTIAL 26 2025 Natural Gas IRP Appendix 262

Input Value Comments
Dependent on energy
Renewable Power resource and location Assuming energy from solar,wind and
Capacity Factor (national vs. regional nuclear sources
averages)
Electrolyzer Energy 53 kWh/kg Based on projects with which ICF is
Consumption Rate familiar and ranges from original
equipment manufacturers (OEMs)
BoP Energy 8 kWh/kg Based on projects with which ICF is
Consumption Rate familiar and ranges from OEMs
Dependent on resource Based on AEO projections for solar and
type(solar,wind, wind LCOEs and ICF estimates from NREL
nuclear or renewable for nuclear LCOE; RECs assumed to come
Electricity Cost energy certificates at a placeholder value of 5% premium to
[RECs]) the LCOE which is varied in the Monte
Carlo analysis due to the regulatory
uncertainties
Water Intake Rate 2.64 gal/kg Based on projects with which ICF is
familiar and ranges from OEMs
$5.63/kgal Industrial utility water with approximately
Water Cost 1% annual escalation from DOE's
Office of Scientific and Technical
Information (OSTI)
Operation Inputs
Stack Membrane Life 10 years Based on projects with which ICF is
familiar
Life of Electrolyzer 80,000 hours Based on projects with which ICF is
Equipment familiar
1% Conservative estimate; levelized
Annual Degradation degradation factor was assumed to have
Rate minimal impact and not included in
analysis
Operating year 333-353 days Based on projects with which ICF is
familiar
Annual Labor Costs $2.95MM ICF's estimate for standalone electrolyzer
facility with -25 staff
Membrane 30%
Based on projects with which ICF is
Replacement Cost as
familiar
%of Direct Capex
Annual Maintenance 3% Based on projects with which ICF is
as % of Capex familiar
Project Finance and Capital Costs
PEM Electrolyzer $1050/kW Based on projects with which ICF is
familiar and bids from OEMs
CONFIDENTIAL 27 2025 Natural Gas IRP Appendix 263

Input Value Comments
Total Installed Cost 2 Based on projects with which ICF is
Factor familiar; can range from 2 — 2.7 depending
on BOP
Learning Curve Rate 22%
ICF's internal model
for Total System
WACC 4% Provided by utilities; varied in the Monte
Carlo analysis
Loan Duration 20 years Based on projects with which ICF is
familiar
ICF assumes electrolyzer costs scale linearly as electrolyzer units are additive much like solar
facilities where additional units are added to increase capacity rather than scaled up volumetrically
by a factor similar to that of industrial plants such as combined cycle gas plants.Similar to solar
where panels are added to increase the output, electrolyzer units can be added to increase the size
of the hydrogen production facility.The BoP can be scaled up,which may result in some cost
savings; however,we have included BoP costs in the total installed cost factor as a percentage of the
electrolyzer capital cost in our assumptions.
ICF includes two sets of tax credits in the green and pink hydrogen model.
• The renewable electricity production tax credit is a per kilowatt-hour(kWh)federal tax credit
included under Section 45 of the U.S.tax code for electricity generated by qualified renewable
energy resources. ICF levelized the tax credit over 20 years and includes $20.86/MWh annual tax
credit from 2025 to 2045.
• ICF levelized the Section 45V tax credit over 20 years.The tax credit by Cl is summarized in the
table below. Since hydrogen projects must be under construction by the end of 2032 to qualify
for 45V credits,the 45V tax credits were modeled until 2035 as a conservative estimate
assuming every new hydrogen facility beginning construction after 2032 may not qualify for the
tax credit. ICF assumed EAC requirements and other requirements for 45V credits are met to
minimize the Cl which doesn't include embodied emissions and receive the maximum credit
amount of$3/kg.
CONFIDENTIAL 28 2025 Natural Gas IRP Appendix 264

Exhibit 28. 45V Hydrogen Investment Tax Credit and Production Tax Credit
45V Hydrogen Investment Tax Credit and Production Tax Credit
Life Cycle Emissions(kg CO2e/kg 1-12) Value of Incentive
PTC 2022$/ Levelized PTC
Low High ITC96 PTC 2022$/kg MMBtu 2022$/MMBtu
2.50 4.00 6.0% 50.60 $4.45 $2.90
1.50 2.50 7.5% 50.75 $5.57 $3.63
0.45 1.50 10.0'/0 $1.00 $7.42 $4.94
0.00 0.45 10.011/0 $3.00 $22.26 $14.51
ITC and PTC apply to facilities whose construction begins by2032. PTC continues for 10 years.Levelizotion is over
20-year operating life.
Technical Potential
ICF determined the technical potential by applying two main constraints:
1. Resource Constraint: ICF used annual forecasts for solar,wind, hydropower, and nuclear
power from AEO Reference Case,assuming a placeholder percentage of 25%of these
resources would be available for hydrogen production.
2. Technology Readiness Constraint: ICF estimated the annual installation of hydrogen plants
using a database of announced hydrogen projects,categorized by technology and state,
assuming no resource limitations.
For each year,the most conservative forecast from these two constraints was selected to create the
technical potential forecast. Initially,the technology readiness constraint was the limiting factor, but
over time,the resource constraint became more conservative.
ICF produced national and regional (Oregon and Washington) models for each hydrogen production
type for differences in technical potential as well as some assumptions for the levelized cost
modeling such as electricity cost and capacity factor. For regional modeling, ICF assumed the
renewable resource potential of the states involved in the Pacific Northwest Hydrogen Hub which
includes Oregon,Washington and Montana. ICF assumes approximately 60% of the AEO resource
potential for the Northwest Power Pool (NWPP) represents Oregon,Washington and Montana.The
60% assumption is an estimate based on the population of Oregon,Washington and Montana
relative to the regions mentioned in the NWPP. For the national modeling, ICF assumed there would
be limitations to transporting hydrogen which will depend on future regulatory and infrastructure
updates (e.g.,transporting hydrogen by blending with natural gas in pipelines). ICF assumed
California is active in hydrogen production projects based on project announcements and
involvement in the Hydrogen Hub projects and closest in proximity to the Pacific Northwest
Hydrogen Hub.Therefore, a placeholder assumption of 5%of projected renewable resource potential
in California would be used as a constraint for the national technical potential for green and pink
hydrogen for Oregon and Washington.The 5% placeholder is subject to change depending on
hydrogen production and demand in California and the hydrogen to be transported to Oregon and
Washington.
CONFIDENTIAL 29 2025 Natural Gas IRP Appendix 265

Technical Potential and Levelized Cost Results Overview
Exhibit 29 shows the hydrogen production from solar,wind and nuclear results for national and regional
(OR and WA) basis and a summary of the range of regional and national results for 2050. ICF assumed
the production tax credit(PTC)for both solar,wind and nuclear energy as well as the PTC for hydrogen
production satisfies all requirements under Section 45Y and 45V, respectively.
Exhibit 29. Summary of Results for Hydrogen Produced from Solar, Wind and Nuclear
cLevelized - LevelizeJr� Resource
Cost Potential Emissions Cost Potential
BBtu (1000 BBtu (1000
$2024 per CO2e kg/ $2024 per CO2e kg/
Unit MMBtu MMBtu) MMBtu MMBtu MMBtu) MMBtu
per year per year
Green H2-Solar(NW) Green H2-Solar(National)
2025 $29.11 197 0 $24.32 970 0
2030 $22.59 23,587 0 $15.43 2,335 0
2035 $20.07 62,223 0 $13.70 3,951 0
2040 $27.93 67,871 0 $27.43 4,580 0
2045 $25.47 68,897 0 $26.96 5,399 0
2050 $33.72 69,027 0 $34.98 5,810 0
Green H2-Wind (NW) Green H2-Wind (National)
2025 $37.04 197 0 $29.98 970 0
2030 $27.59 23,587 0 $25.32 2,335 0
2035 $26.16 62,223 0 $23.55 3,951 0
2040 $40.36 67,871 0 $38.34 4,580 0
2045 $39.77 68,897 0 $37.89 5,399 0
2050 $49.05 69,027 0 $47.34 5,810 0
Pink H2(NW) Pink H2(National)
2025 $30.51 22 1.09 $30.88 108 1.09
2030 $27.48 2,021 0.99 $27.87 - 0.99
2035 $26.07 2,021 0.97 $26.41 - 0.97
2040 $40.45 2,021 0.97 $40.64 - 0.97
2045 $40.15 2,021 0.96 $40.16 - 0.96
2050 $48.58 1,974 0.95 $48.42 - 0.95
The impact of the Monte Carlo process on costs is illustrated in Exhibit 30.The histogram depicts
the number of the 1,000 Monte Carlo cases (y-axis) that fall within various cost ranges/technical
potential ranges (x-axis)for each type of green and pink hydrogen.21
25 Note: 1 MMBtu = Million (101) Btu.1 BBtu = Billion (101) Btu.1 TBtu = Trillion (1012) Btu.
CONFIDENTIAL 30 2025 Natural Gas IRP Appendix 266

Exhibit 30. Summary of Monte Carlo Simulation Results for Hydrogen Produced from Solar, Wind and
Nuclear(Oregon and Washington, 2050)
Green Hydrogen - Solar
160 160
140 140
120 120
100 100
80 80
60 60
40
40 20
20 — 0
O M M M M M M M M M M M M M M M M M M M M M
N (f) 00 �--� 't n O M (D M N (P) OD �--i V n O M (D D)
M M M M M M M M M M M M M V V V V (n ((1 (n (n ((1 (D (D (D (D Ili
r, r,'n OO OO O OD OO a) D)
�A �A 43 43 43 43 43 14 43 43 14 43 � M 3 14 14 M M M M M M M M M'co M M co M M'co M M M M
O O �--� N Co- Co- V (C) (f) (D n W N O O O �--� CO Q) N NOR �--I V n O M (q M " (n OR c-i V � O M (D
M M M M co co M co co M co co M M V V V (n n O N V n M V O W O co N n co N V n M �--i
ft t2e 44
— EFT t2 tt EFT t2 tt EFT t2 tt 7Ft t2 tt ER EA V V (C) (17 LL7 (f7 (17 (D (D (D (D n n n n W OO OO 00 00 O
❑ Levelized Cost(2050,2024$/MMBtu) ❑ Resource Potential(2050,Tbtu/Year)
Levelized Resource
Cost Potential
Mean $34.77 Mean 69
Max $41.23 Max 92
Min $29.64 Min 46
IQR $2.78 IQR 9
Green Hydrogen -Wind
160 160
140 140
120 120
100 100
80 80
60 60
40 40
20 20
0 — 0
(M V (n (D I* OO
�--� N (`) V 6 (D I-� W D) O N M* V (f) (D I" N M O M N Uf 00 n O M (O q N LI) 00 (O q
V V V V V V V V V u) i!) X) (f) (f) u) u) (D (D n O N V n M .--i V (O w O m N N O N V n M .--i M
YJ fR iA Y3 1fi EA iA ER(fi EPr EA ER iR 1fi EPr fR ER ER EPr EA V (n N N N N M O O O n n n n W 00 00 00 W W M
M O N N M VU� (D n 00 g O N N M V Lq (D n Oq M P'7 M P'7 P'7 P'7 P'7 P'7 P'7 M M M M M M cli cli cli cli(`M M
D) " N co V (N (D N co M O N co V (N (D n OD M O (D O N (n 00 -! V n O M (O W N N OR -! V n O M (O
co V V V V V V V V V (N (D to to LN V) (D to to (D (() N O N V N a) .--� V (D 00 O co u) N O N V N a) .--i
tt t23 t2)tt t2 7n tt tt fA tf tf t2)tt t ti tt tt fA ti tf V V (17 (17 (17 (17 (17 (D (D (D (D n n n n W 00 00 00 00 O)
❑ Levelized Cost (2050,2024$/MMBtu) ❑ Resource Potential(2050,TBtu/Year)
CONFIDENTIAL 31 2025 Natural Gas IRP Appendix 267

Levelized Resource
Cost Potential
Mean $50.28 Mean 69
Max $61.15 Max 92
Min $39.95 Min 46
IQR $4.02 IQR 9
Pink Hydrogen
160 160
140 140
120 120
100 — 100
80 80
60
60
40
40
20 -
0 I 20
0
(M M V L6 N M n c6 c6 oi O �--i c-i N M V V
V V V V V -It V V V V LO LO N LO V) N n V N I�V e-i I�V N c0 V e-i W 77 c0 77 cO N
fA H} ER ifi 11! 11! (R 11! EH H} ER ifi fH In (R E! [A 117 V Lq to (D n n o0 O O� O -i '-I N M M V to to M
N O r� Lq N O n V N (O V - O (D M �--� N N N N N N N N N N
N M M V In
V V V V O \ 0 0 O O V M V i W-- V W -If - W
V Iq V V V V V u7 M M lC u CM MVV1N (O rl: n M O O O '- NCM MVUJ Ufi
fR ER EPr ER tt t2 EFT 1A t2 iA t2e EFT tt t2 7Ft t2o (A ! 7 7 7 7 '-I 7 7 7 N N N N N N N N N
❑ Levelized Cost (2050,2024$/MMBtu) ❑ Resource Potential(2050,TBtu/Year)
Resourc
Levelized Cost e
Mean $48.18 Potential
Max $54.77 Mean 2.0
Min $42.24 Max 2.6
IQR $2.82 Min 1.3
IQR 0.3
The levelized cost of hydrogen ranged from approximately $30/MMBtu to $61/MMBtu depending on
the production method shown in Exhibit 30 for 2050. The costs increased after 2035 because of the
removal of the 45V tax credit for new hydrogen facilities beginning construction after 2032.The largest
cost contributor to the levelized cost of hydrogen is the cost of electricity which will vary depending
on factors such as 45V tax credit amendments regarding EACs,future hydrogen demand,etc.Similarly,
the technical potential may vary depending on the same factors, hydrogen infrastructure
development, and the amount of renewable energy resources allocated to hydrogen production. For
pink hydrogen, the national resource potential is based on AEO's nuclear energy generation forecast
which is assumed to be zero after 2025.
CONFIDENTIAL 32 2025 Natural Gas IRP Appendix 268

Blue Hydrogen (Steam Methane Reforming)
Levelized Cost
Steam methane reforming (SMR) converts a hydrocarbon feedstock(such as natural gas) into a
syngas by reacting the feedstock with steam in the presence of a catalyst, located inside multiple
reformer tubes,to produce carbon monoxide, hydrogen and some carbon dioxide.The heat required
for the reforming reactions is provided by external heating of the reformer tubes, by burners placed
outside the tubes. Maximum hydrogen production is achieved by"shifting" as much of the carbon
monoxide to hydrogen as feasible and hydrogen recovery from the syngas via a pressure swing
adsorption (PSA) unit. Approximately 60% of the cost of a steam reformer is the cost of the reformer
tubes,tube supports and catalysts and these items scale approximately linearly with capacity and
therefore hydrogen production via SMR may not achieve efficient economies of scale at higher
hydrogen capacities.
Autothermal Reforming(ATR) generates the heat required for the reforming reactions, internally in
the process by oxygen in addition to the process burner,which partially oxidizes the syngas.The
reforming reactions are carried out downstream of the burner in a catalyst bed, installed inside a
refractory lined vessel,generally mounted below the burner. Like with SMR, hydrogen production is
maximized by shifting any carbon monoxide to hydrogen in a CO shift unit and then using a PSA to
recover a high purity hydrogen product. As the ATR reactor is a refractory lined vessel, partially filled
with catalyst, higher capacities can be readily achieved by increasing the reactor diameter, up to a
practical maximum vessel size. Hence, at high hydrogen capacities,the ATR tends to be more
economic than similar capacity SMR-based plants.
With suitable CO2 recovery technologies, both processes can produce relatively pure CO2 streams
which make them well situated to downstream compression, (pipeline)transportation and
sequestration technologies.To reduce carbon intensity associated with the produced hydrogen
further,these facilities can also replace natural gas with renewable natural gas.
Exhibit 31. ATR Facility Production Cost Inputs
Input Value Comments
Sample Facility Size
Nameplate Capacity 8,929 kg/h Based on projects with which
ICF is familiar
Annual Production Target 78,218,040 kg Based on projects with which
ICF is familiar
Assume plant is offline for
Plant Utilization Rate 92% approximately 4 weeks for
maintenance, etc.
Carbon Capture Percent 97% Based on estimates for efficient
carbon capture technology
Energy and Water Inputs
Natural Gas Thermal 84% Based on projects with which
0
Efficiency ICF is familiar
Natural Gas Share of Optimized to reduce carbon
Feedstock 95% intensity to receive IRA tax
credits
CONFIDENTIAL 33 2025 Natural Gas IRP Appendix 269

Input Value Comments
Optimized to reduce carbon
RNG Share of Feedstock 5% intensity to receive IRA tax
credits
Dependent on varying Based on ICF's RNG model
RNG and Natural Gas Cost natural gas values from (including a 10% premium) and
Henry Hub or RNG cost natural gas costs from Henry
model Hub
Based on projects with which
Electricity Consumption Rate 2.57 kWh/kg ICF is familiar and ranges from
OEMs
Electricity Cost Grid electricity Based on AEO projections
forecast
Based on projects with which
Water Intake Rate 20.78 gal/kg ICF is familiar and ranges from
OEMs
Industrial utility water with
Water Cost $5.63/kgal approximately 1% annual
escalation from OSTI
Operation Inputs
Based on projects with which
Annual Maintenance Share 5.5% ICF is familiar; includes labor
costs
Plant Life 20 years Based on projects with which
ICF is familiar
Project Finance and Capital Costs
Total Investment per Unit of Based on projects with which
Annual Capacity $10.50/kg ICF is familiar and bids from
OEMs
Total Capital Investment $820 MM Based on projects with which
ICF is familiar
Technology Improvement 0.75%/year ICF's estimate based on
literature
WACC 4% Provided by utilities;varied in
the Monte Carlo analysis
Loan Duration 20 years Based on projects with which
ICF is familiar
Technical Potential
The technical potential for blue hydrogen follows a similar approach to Section 4.2.2; however, unlike
the technical potential for electrolyzers, ICF did not impose resource constraints on blue hydrogen
since natural gas and RNG are assumed to be accessible. Blue hydrogen can be produced solely
from natural gas; however, this would increase emission intensity, potentially disqualifying it from the
highest hydrogen production tax credit. For the NW regional model, ICF assumes the technical
CONFIDENTIAL 34 2025 Natural Gas IRP Appendix 270

potential of hydrogen production in the region based on technical readiness constraints such as
project announcements and estimate forecasts of hydrogen facilities in OR and WA. For the national
model, ICF assumes a placeholder value of 5% of California's technical readiness potential which
would be delivered to OR and WA. Similar to the green and pink hydrogen technical potential for the
national modeling,the 5% placeholder is subject to change depending on hydrogen production and
demand in California and the hydrogen to be transported to Oregon and Washington.
Technical Potential and Levelized Cost Results Overview
Exhibit 32 shows the hydrogen production results from natural gas and RING used in an ATR facility
for national and regional (OR and WA) basis and Exhibit 32 shows a summary of the range of regional
and national results for 2050. ICF assumes the PTC for hydrogen production satisfies all
requirements under Section 45Y and 45V, respectively.
Exhibit 32. Summary of Results for Blue Hydrogen
Levelized Resource GHG
Cost Potential Emissions Cost Potential Emissions
BBtu (1000 BBtu (1000
$2024 per CO2e kg/ $2024 per COze kg/
Unit MMBtu MMBtu) MMBtu MMBtu MMBtu) MMBtu
per year per year
Oregon and Washington National (Available to OR and WA)
2025 $12.80 - 2.90 $15.36 97 1.50
2030 $12.91 16,845 2.88 $14.51 3,359 2.89
2035 $14.51 52,942 1.80 $15.81 7,690 2.62
2040 $26.59 101,071 18.20 $27.21 13,466 20.99
2045 $26.82 149,201 18.32 $27.43 19,241 20.79
2050 $26.94 197,330 18.37 $27.42 25,017 20.49
The impact of the Monte Carlo process on costs is illustrated in Exhibit 33.The histogram depicts
the number of the 1,000 Monte Carlo cases (y-axis)that fall within various cost ranges/technical
potential ranges (x-axis)for blue hydrogen.
CONFIDENTIAL 35 2025 Natural Gas IRP Appendix 271

Exhibit 33. Summary of Monte Carlo Simulation Results for Blue Hydrogen (Oregon and Washington,
the Year 2050)
160 160
140 140
120 120
100 100
80 80
60 60
40 40
20 20 —
0 0 `
'i Cq L N G C(O M O n V -i W L NO� CID M O n V
N N In N N N N r-ZN N N N N N N O O .--I M M O n M O r` V O M V O r` -ItN O M V M M V
N N N N N N N N N N N N N N M M M M V 47 (O r` r` W (T (n C C C C C M C C17 Cf7 CO
EPr V3 EH [H [H 1f3 (A V) EH [H (f3 1f3 1f} EH H3 [H tf3 .--i .--i .--i .--i .ti .--i .--i .--i .--i .ti N N N N N N N N N N
00 N Il Lq (T M W N CO O V (r co I� .� Ln V V V V V V V V V V V V V V V V V V V V
co V V q CD CD I� r` co c0 W (. O O '~ co LO N CD (D co O r` V e-i c0 LO N (n CO M O r`
N N N N N N N N N N N N N N N M M O I� M O n M O n V O I� V O I� V O I� V ti n
Y} Y} iA EA CO M V LO Cn CO r` n CD (n M O N M CO V LO LO
�--� �--� �--� �--� �--� •--� �--� �--� �--� �--� N N N N N N N N N
❑ Levelized Cost (2050, 2024$/MMBtu) ❑ Technical Potential(2050,Tbtu/year)
Levelized Technical
Cost Potential
Mean $27.45 Mean 197
Max $30.93 Max 264
Min $23.82 Min 130
IQR $1.71 IQR 26
For blue hydrogen,a percentage of RNG was assumed to reduce the Cl score for 45V tax credits by
optimizing the ratio of RNG relative to natural gas as feed.The 45V tax credits were Ievelized over a
20-year period and applied to the model before 2035.
CONFIDENTIAL 36 2025 Natural Gas IRP Appendix 272

Turquoise Hydrogen (Methane Pyrolysis)
Levelized Cost
Turquoise hydrogen or methane pyrolysis is the process where methane is broken down into
hydrogen gas and solid carbon through thermal energy. Natural gas or renewable natural gas could
be used as feedstock to pyrolysis facilities.There are several pyrolysis methods:thermal, catalytic
and plasma pyrolysis.Thermal pyrolysis involves the breakdown of methane from high temperatures.
Catalytic pyrolysis involves the usage of catalysts such as iron, nickel, etc.and requires less
temperature compared to thermal pyrolysis. Plasma pyrolysis uses plasma, a charged gas,which is
used to break down methane molecules. Pyrolysis is typically considered to be low carbon
technology as there are no combustion emissions in the main process. Carbon black is typically a
co-product and can be sold to be used for pigments and reinforcement materials for rubber, asphalt,
etc. ICF shows a conservative carbon black price range in the model ($0/kg to $0.50/kg);for
example,the $0.50/kg price for carbon black could result in approximately in offsetting the cost of
hydrogen production by $11/MMBtu hydrogen.The table below shows a representative levelized cost
inputs for a microwave plasma pyrolysis unit.
Exhibit 34. Pyrolysis Facility Production Cost Inputs
Input Value Comments
Sample Facility Size
Pyrolysis Nameplate Capacity 1,000 kg/d Based on OEM estimates
Annual Production Target 339,500 kg Based on OEM estimates
Margin for Annual Production 93% Based on projects with which ICF
is familiar
3 kg carbon
Carbon Black Yield black/kg hydrogen Based on projects with which ICF
is familiar
(for plasma)
Energy and Water Inputs
1.8 MMBtu/MMBtu
NG or RNG Consumption Hydrogen (for Based on OEM estimates
Plasma)
Natural Gas Share of Feedstock 95% Optimized to reduce carbon
intensity to receive IRA tax credits
RNG Share of Feedstock 5% Optimized to reduce carbon
intensity to receive IRA tax credits
Based on ICF's RNG model
(including an estimate 10%
RNG and Natural Gas Cost premium to the levelized cost)
and natural gas costs from Henry
Hub
Plasma Pyrolysis Electricity 12 kWh/kg Based on OEM estimates
Consumption
BOP Energy Consumption Rate 2.5 kWh/kg Based on OEM estimates
Electricity Cost Dependent on AEO costs for grid
power
Operation Inputs
CONFIDENTIAL 37 2025 Natural Gas IRP Appendix 273

Based on projects with which ICF
Plant Life 20 years
is familiar
Annual Labor Costs as of Capex 2% ICF's estimate
Annual Major Maintenance as % 1% Based on projects with which ICF
of Capex is familiar
Annual Maintenance as % of Based on projects with which ICF
Capex 1.5% is familiar
Project Finance and Capital Costs
Total Capital Cost (Pyrolysis Unit $7 MM Based on ICF assumptions and
+ BOP) OEM estimates
ICF's estimate using a percentage
Technology Improvement 5%/year of global electrolyzer capacity
projection as a placeholder for
pyrolysis technology capacity
WACC 4% Provided by utilities;varied in the
Monte Carlo analysis
Loan Duration 20 years Based on projects with which ICF
is familiar
Technical Potential
ICF applied the same methodology as that used to assess the technical potential of blue hydrogen;
therefore, no resource constraints were used.Since there is limited data for the technical readiness
constraint based on project announcements,the technical readiness of the pyrolysis units was
assumed to be based on a 10-year delayed project forecast for electrolyzer projects as a
placeholder for the regional and national modeling. For the NW regional model, ICF assumes the
technical potential of hydrogen production in the region based on technical readiness constraints
such as project announcements and estimate forecasts of hydrogen facilities in OR and WA. For the
national model, ICF assumes a placeholder value of 5% of California's technical readiness potential
which would be delivered to OR and WA. Similar to the green and pink hydrogen technical potential
for the national modeling,the 5% placeholder is subject to change depending on hydrogen
production and demand in California and the hydrogen to be transported to Oregon and
Washington.
Technical Potential and Levelized Cost Results Overview
Exhibit 35 shows the turquoise results for national and regional (OR and WA) basis and Exhibit 35
shows a summary of the range of regional and national results for 2050. ICF assumes the PTC for
both solar,wind and nuclear energy as well as the PTC for hydrogen production satisfies all
requirements under Section 45Y and 45V, respectively.
CONFIDENTIAL 38 2025 Natural Gas IRP Appendix 274

Exhibit 35. Summary of Results for Turquoise Hydrogen
Cost Potential Emissions Cost Potential Emissions
BBtu (1000 BBtu (1000
$2024 per COze kg/ $2024 per COze kg/
Unit MMBtu MMBtu) MMBtu MMBtu MMBtu) MMBtu
per year per year
Turquoise Hz-Plasma(NW) Turquoise Hz- Plasma(National)
2025 $32.55 - 3.27 $36.71 - 32.42
2030 $32.31 62 3.27 $35.65 1 18.88
2035 $34.40 197 3.27 $37.73 970 16.36
2040 $44.03 23,587 31.35 $46.99 2,335 44.67
2045 $44.75 67,806 31.93 $47.66 6,480 43.73
2050 $45.95 143,609 32.18 $48.24 13,587 42.29
The impact of the Monte Carlo process on costs is illustrate in Exhibit 36. The histogram depicts the
number of the 1,000 Monte Carlo cases (y-axis)that fall within various cost ranges/technical potential
ranges (x-axis) for turquoise hydrogen.
CONFIDENTIAL 39 2025 Natural Gas IRP Appendix 275

Exhibit 36. Summary of Monte Carlo Simulation Results for Turquoise Hydrogen - Plasma Pyrolysis
(Oregon and Washington, the Year 2050)
160 160
140 140
120 120
100 100
80 80
60 60
40
40
2
20 0
0 17F - 0 M M M M M M M M M M M M M M M M M M M M M
W N W W �--� V r` O M W M N Lq c0 �--� V r` O M W M
r` O N V I� M c-I V (O W O M (f7 I� O N V I� W �--i co
M M M M M M M M M M M M M V V V V V (n ifl � u7 � (O (O (O (O n r r n W W W W W M M
M co M M M M M M M M M M M M M M M M co M M
O O .--i N M M V m W W r` W c0 M O O .--i M a? N (n c0 -1 V n O M (p M " W c0 _! V n O M (O
M M M M co M M M M M M M M M V V V (fl I" O N V r` M r-i V CO W O M W r` O N V I" W .-i
fA (A EH EA (A fR (A EH fR (A ER EA EH fR iA EH fR V V W W W W W W W W W r` r` r` r\ W W W W W M
❑ Levelized Cost (2050,2024$/MMBtu) ❑ Resource Potential(2050,Tbtu/Year)
Levelized Resource
Cost Potential
Mean $34.77 Mean 69
Max $41.23 Max 92
Min $29.64 Min 46
IQR $2.78 IQR 9
Similar to blue hydrogen,a percentage of RNG was assumed to reduce the Cl score for 45V tax
credits by optimizing the ratio of RNG relative to natural gas as feed.The 45V tax credits were
levelized over a 20-year period and applied to the model before 2035.
Transportation and Storage of Hydrogen
Transporting Hydrogen
Currently hydrogen is liquefied or compressed before being transported via on-road tube trailers.
The tube trailer is a relatively mature technology that has been utilized for decades for the
transportation of compressed and liquefied industrial gases such as carbon dioxide and nitrogen.
Compressed trailers require pressures ranging from 200 — 500 bar,while liquefied hydrogen tube
trailers require lower pressures, ranging from 6 —12 bar.The lower density of the compressed
hydrogen correlates to a higher transportation cost compared to liquefied hydrogen which is 2-3
times denser.
As a result of demand generally exceeding the supply available from compressed hydrogen,
compressed hydrogen truck transport is only economically competitive for transporting short
CONFIDENTIAL 40 2025 Natural Gas IRP Appendix 276

distances (< 200km)for customers with small hydrogen demands.As distribution distances increase
past 200 km,the higher transportation capacities of liquefied hydrogen trailers become
economically favorable. However, liquid hydrogen trailers suffer from boil-off rates (1-5%)that result
in losses in delivered hydrogen capacity; some of the vaporized hydrogen may be returned to the
liquefaction facility and re-entered into the delivery stream to fill the trailers.
As of 2024,there are 1,600 km of dedicated hydrogen pipelines in the United States, most of this
infrastructure is repurposed natural gas pipelines. There is considerable interest in blending
hydrogen into pipelines, however there are regulatory considerations involving the amount of
hydrogen blend acceptable in a transmission or distribution line,and safety mitigation efforts for
hydrogen leakage or pipeline embrittlement that would need to be addressed prior to blending
hydrogen into natural gas pipelines For example, operating at lower pressures could reduce the risk
of hydrogen pipeline embrittlement. Many utilities are testing small hydrogen blends through the
distribution pipeline; Hawaii Gas contains up to 12-15% hydrogen21 in their natural gas pipelines which
is one of the highest hydrogen blends used by a utility company as of 2024. Depending on the end
use, purification systems to remove the hydrogen from the blend may also be needed. Hydrogen
separation technologies such as membrane separation or pressure swing adsorption could be used
to extract a higher purity of hydrogen depending on the hydrogen offtake customer. ICF estimated
the cost of a pure hydrogen pipeline in Exhibit 37 below assuming 1.66 kWh/MT-mi.
Exhibit 37. Hydrogen Pipeline Cost Summary
Pipeline Flow Capacity • of
Flow RM
Outside Cost in in MMscf per Capacity Capacity in 50 Service for
•. •• •- • Miles
MMBtu/day Miles
• 14.73 • • •. C
8.00 $161,543 40 102 13,720 $64.6 $1.71
10.00 $170,045 90 229 30,870 $85.0 $1.03
12.75 $188,939 182 464 62,552 $120.4 $0.74
16 $196,787 334 851 114,706 $157.4 $0.55
24 $211,911 946 2,407 324,403 $254.3 $0.34
30 $217,654 1,663 4,234 570,515 $326.5 $0.27
36 $223,397 2,638 6,715 904,890 $402.1 $0.22
42 $229,140 3,897 9918 1,336,507 $481.2 $0.19
Storage and Liquefaction
Hydrogen is traditionally either stored as liquid, a compressed gas, or at low pressures in high-
volume vessels.Storing hydrogen as a compressed gas requires high pressure vessels ranging from
350 to 700 bar, requiring between 1.05 and 1.36 kWh/kg respectively. Liquid hydrogen can be stored
21 More information available online here.
CONFIDENTIAL 41 2025 Natural Gas IRP Appendix 277

at lower pressures and higher volumetric densities, albeit requiring cryogenic tanks to sustain low
temperatures of approximately -423 degrees Fahrenheit.This storage method requires between 10-
12 kWh/kg of energy for liquefaction with current technologies.When electrolyzer stacks are paired
with an intermittent electricity source, compression and liquefaction systems must be designed to
have the capacity to handle the maximum hydrogen production rates during peak energy production
hours.
Due to the low temperatures required for liquefaction, many developers do try to reduce the number
of times the systems get turned off to limit the thermal cycling of the equipment and time it takes to
start up. Newer systems are being designed for better integration with intermittent power, so future
systems may be more capable of rapid startup and shutdowns. Finally,transportation hydrogen
value is impacted by the use of grid electricity to liquefy hydrogen,so future systems may be able to
monetize the ability to shut down and start up quickly. The Section 45V credits are well to gate, so
electricity for liquefaction is not included within the calculations for the tax credit.
In a recent analysis conducted by NREL21, liquefaction costs were estimated to be in the range of
$2.70-$5.20/kg for facilities ranging from 50,000/kg per day to 1 million/kg per day, and terminal
storage costs in the range of $0.20-$1.00/kg.
Industry is also considering salt caverns as a potential long term storage medium that requires
pressures of only 30 bar,which is already achieved in the production of hydrogen from industry
typical PEM electrolyzers. Salt caverns can be both naturally occurring, or solution mined in salt
formations. Historically salt caverns have been utilized for rapid cycling natural gas storage because
of their low permeability to natural gas,so these facilities may be suitable for repurposing for
hydrogen storage.The salt caverns typically require 30-40% cushion gas which is hydrogen used to
maintain the pressure of cavern, however, other gases such as nitrogen are being studied as options
for cushion gas28.According to the U.S. Department of Transportation,there are approximately 36
salt caverns in the U.S. used for natural gas and most are in the Gulf Coast29.There are also studies
including ongoing research from Sandia National Laboratories30 that show the potential of hydrogen
to be used in depleted oil and natural gas reservoirs as additional gaseous storage methods.
Based on ICF's internal cost analysis,the annualized cost over a 20-year period with a 9% interest
rate for storage in large cryogenic tanks is approximately $2 to$4/kg depending on electricity costs
including liquefaction for liquid hydrogen and approximately less than $1/kg of additional levelized
cost for salt cavern storage for large production facilities.The useful life of liquid storage tanks are
estimated to be up to 30 years31,assuming cycling or storing and releasing of hydrogen to be
approximately weekly.
27 https://www.nrel.gov/docs/fy24osti/88818.pdf
28 https://www.sciencedirect.com/science/article/abs/pii/S2352152X21014560
29 Fact Sheet: Underground Natural Gas Storage Caverns I PHMSA (dot.gov)
30 https://newsreIeases.sandia.gov/subterranean hydrogen/
31 DOE Technical Targets for Hydrogen Delivery I Department of Energy
CONFIDENTIAL 42 2025 Natural Gas IRP Appendix 278

Exhibit 38. Storage and Transport Assumptions for Hydrogen
Variable Units Values
2MM kg underground storage w/55 mi of pipeline&1930 kW compressor
Capacity kg 2,000,000
Gas Storage Capex $/kg $50.13
Gas Storage w/TIC $ $100,251,543
Gas storage PMT(with withdrawal & injection cost) $/MMBtu $4.21
$/kg $0.48
Liquefaction
Liquefaction levelized cost from NREL $/kg $3.76
$/MMBtu $33.17
300,000 kg cryogenic tank
Capacity kg 300000
Cryo tanks Capex $ $9,464,306
Cryo tanks w/TIC $18,928,613
Cryo tank PMT $/MMBtu $0.78
$/kg $0.09
Liquid H2 Trucking
Trucking Adder(Liq 1-12)for 100 mi $/kg $0.26
$/MMBtu $2.29
CONFIDENTIAL 43 2025 Natural Gas IRP Appendix 279

Synthetic Methane
Resource Type
ICF considered two pathways for synthetic methane production: a) biomass gasification and b)
methanation of hydrogen combined with various carbon dioxide resources (we are referring to this
here as power-to-gas).
Biomass Gasification
Biomass like agricultural residues,forestry and forest produce residues, and energy crops have high
energy content and are ideal candidates for thermal gasification.The thermal gasification of biomass
to produce RNG occurs over a series of steps.Thermal gasification typically requires some pre-
processing of the feedstock.The gasification process first generates synthesis gas (or syngas),
consisting of hydrogen and carbon monoxide. Biomass gasification technology has been
commercialized for nearly a decade; however,the gasification process typically yields a residual tar,
which can foul downstream equipment. Furthermore,the presence of tar effectively precludes the
use of a commercialized methanation unit.The high cost of conditioning the syngas in the presence
of these tars has limited the potential for thermal gasification of biomass. Over the last several years,
however, several commercialized technologies have been deployed to increase syngas quantity and
prevent the fouling of other equipment by removing the residual tar before methanation.There are a
handful of technology providers in this space including Haldor Topsoe's tar reforming catalyst.
Frontline Bioenergy takes a slightly different approach and has patented a process producing tar
free syngas (referred to as TarFreeGas).The syngas is further upgraded via filtration (to remove
remaining excess dust generated during gasification), and other purification processes to remove
potential contaminants like hydrogen sulfide, and carbon dioxide.The upgraded syngas is then
methanated and dried prior to pipeline injection.
ICF notes that biomass, particularly agricultural residues,are often added to anaerobic digesters to
increase gas production (by improving carbon-to-nitrogen ratios, especially in animal manure
digesters). It is conceivable that some of the feedstocks considered here could be used in anaerobic
digesters. For the sake of simplicity, ICF did not consider any multi-feedstock applications in our
assessment; however, it is important to recognize that the RNG production market will continue to
include mixed feedstock processing in a manner that is cost-effective.
Exhibit 39. Biomass Resources Considered
--. Description
Agricultural Residue Material left in the field,orchard,vineyard, or other agricultural setting
after a crop has been harvested
Forestry Residue Biomass generated from logging,forest and fire management activities,
and milling. Inclusive of logging residues (e.g., bark,stems, leaves,
branches),forest thinnings (e.g., removal of small trees to reduce fire
danger), and mill residues (e.g.,slabs, edgings,trimmings, sawdust)
Energy Crops Inclusive of perennial grasses,trees,and some annual crops that can
be grown specifically to supply large volumes of uniform, consistent
quality feedstocks
CONFIDENTIAL 44 2025 Natural Gas IRP Appendix 280

--• • Description
MSW The trash and various items that household, commercial,and industrial
consumers throw away—including materials such as glass,construction
and demolition (C&D) debris,food waste, paper and paperboard,
plastics, rubber and leather,textiles,wood,and yard trimmings.
Methanated Hydrogen via P2G
Power-to-gas (P2G) is a form of energy technology that converts electricity to a gaseous fuel.
Electricity is used to split water into hydrogen and oxygen, and the hydrogen can be further
processed to produce methane when combined with a source of carbon dioxide. If the electricity is
sourced from renewable resources,such as wind and solar,then the resulting fuels are carbon
neutral.The key process in P2G is the production of hydrogen from renewably generated electricity
by means of electrolysis.This is covered in More detail in Section 4.
ICF considers P2G as a synthetic methane production pathway whereby the combination of
hydrogen and carbon dioxide (CO2)yield methane. Methanation may be attractive because it avoids
the cost and potential inefficiency associated with hydrogen storage and creates more flexibility in
the end use through the natural gas system.
The table below summarizes the geography, hydrogen and COZ sources considered in the P2G
analysis. ICF assumes that the hydrogen would be the limiting resources and restricted the hydrogen
supply in line with constraints imposed and discussed previously in Section 4.
Exhibit 40. List of Data Sources for RNG Feedstock Inventory
Oregon &Washington Green hydrogen, solar Biogenic
National Green hydrogen,wind CCS
Pink hydrogen Direct air capture
Resource Potential
Biomass Gasification
ICF used a mix of existing studies, government data, and industry resources to estimate the current
and future supply of the feedstocks.The table below summarizes some of the resources that ICF
drew from to complete our resource assessment, broken down by feedstock.
Exhibit 4L List of Data Sources for RNG Feedstock Inventory
Feedstock - Resources - -
nt
Agricultural residue • U.S. DOE Billion Ton Report
• Bioenergy Knowledge Discovery Framework
• U.S. DOE Billion Ton Report
Energy crops • Bioenergy Knowledge Discovery Framework
CONFIDENTIAL 45 2025 Natural Gas IRP Appendix 281

Feedstock - Resources - -
nt
Forestry and forest product residue ' U.S. DOE Billion Ton Report
• Bioenergy Knowledge Discovery Framework
MSW • U.S. DOE Billion Ton Report
• Waste Business Journal
This RNG feedstock inventory does not take into account resource availability—in a competitive
market, resource availability is a function of factors, including but not limited to demand,feedstock
costs,technological development, and the policies in place that might support RNG project
development. ICF assessed the RNG resource potential of the different feedstocks that could be
realized given the necessary market considerations.
Similar to feedstocks used to produce RNG (Section 3), ICF assumed that the Utilities would have
"first-mover access"to synthetic methane produced via biomass gasification from domestic
resources. ICF used the same approach here:we reviewed states that have robust policy frameworks
in place to advance RNG (with the understanding that synthetic methane produced via biomass
gasification would generally be defined as RNG) deployment in the state (but not necessarily
exclusively within their state) and assumed that NW Natural,Avista Utilities, and Cascade Natural Gas
Corporation would have a population-weighted share of first-mover access to national resources.
ICF also included British Columbia and Quebec in our consideration of first movers because these
two Canadian provinces have robust RNG policies in place and have already procured significant
amounts of US-based RNG. ICF's assumption regarding first mover access yields a result whereby
the Utilities will likely be able to access up to about 13%of the total domestic RNG production,which
about 3.5-4 times greater than the simple population-weighted share that one might otherwise
assume.
Agricultural Residue
Agricultural residues include the material left in the field, orchard,vineyard, or other agricultural
setting after a crop has been harvested. More specifically,this resource is inclusive of the unusable
portion of crop,stalks,stems, leaves, branches, and seed pods.Agricultural residues (and sometimes
crops) are often added to anaerobic digesters
ICF extracted information from the U.S. DOE Bioenergy KDF including the following agricultural
residues:wheat straw, corn stover, sorghum stubble, oats straw, barley straw, citrus residues,
noncitrus residues,tree nut residues,sugarcane trash, cotton gin trash, cotton residue, rice hulls,
sugarcane bagasse,and rice straw.The table below lists the energy content on a high heating value
(HHV) basis for the various agricultural residues included in the analysis—these are based on values
reported by the California Biomass Collaborative.To estimate the RNG production potential, ICF
assumed a 65% efficiency for thermal gasification systems.
Exhibit 42. Heating Values for Agricultural Residues
Component
Wheat straw 7,527 15.054
Corn stover 7,587 15.174
Sorghum stubble 6,620 13.24
Oats straw 7,308 14.616
CONFIDENTIAL 46 2025 Natural Gas IRP Appendix 282

Component
Barley straw 7,441 14.882
Citrus residues 8,597 17.194
Noncitrus residues 7,738 15.476
Tree nut residues 8,597 17.194
Sugarcane trash 7,738 15.476
Cotton gin trash 7,058 14.116
Cotton residue 7,849 15.698
Rice hulls 6,998 13.996
Sugarcane bagasse 7,738 15.476
Rice straw 6,998 13.996
Forestry and Forest Product Residues
Biomass generated from logging,forest and fire management activities, and milling. Inclusive of
logging residues (e.g., bark,stems, leaves, branches),forest thinnings (e.g., removal of small trees to
reduce fire danger),and mill residues (e.g.,slabs, edgings,trimmings,sawdust) are considered in the
analysis.This includes materials from public forestlands (e.g., state,federal), but not specially
designated forests (e.g., roadless areas, national parks,wilderness areas) and includes sustainable
harvesting criteria as described in the U.S. DOE Billion-Ton Study, including:
• Alterations to the biomass retention levels by slope class (e.g.,slopes with between 40% and 80%
grade included 40% biomass left on-site,compared to the standard 30%).
• Removal of reserved (e.g.,wild and scenic rivers,wilderness areas, USFS special interest areas,
national parks) and roadless designated forestlands,forests on steep slopes and in wet land areas
(e.g., stream management zones), and sites requiring cable systems.
• The assumptions only include thinnings for over-stocked stands and didn't include removals
greater than the anticipated forest growth in a state.
• No road building greater than 0.5 miles.
These sustainability criteria provide a robust assessment of available forestland. ICF extracted
information from the U.S. DOE Bioenergy KDF,which includes information on forest residues such as
thinnings, mill residues, and different residues from woods (e.g., mixedwood, hardwood, and
softwood).The table below lists the energy content on a HHV basis for the various forest and forest
product residue elements considered in the analysis.To estimate the RNG production potential, ICF
assumed a 65% efficiency for thermal gasification systems.
Energy Crops
Energy crops are inclusive of perennial grasses,trees,and some annual crops that can be grown
specifically to supply large volumes of uniform, consistent quality feedstocks for energy production.
ICF extracted data from the Bioenergy KDF.The table below lists the energy content on a HHV basis
for the various energy crops included in the analysis.To estimate the RING production potential, ICF
assumed a 65% efficiency for thermal gasification systems.
Exhibit 43. Heating Values for Energy Crops
Energy Crop Btu/lb, MMBtu/ton,
dry dry
Willow 8,550 17.10
CONFIDENTIAL 47 2025 Natural Gas IRP Appendix 283

Energy Crop Btu/lb, MMBtu/ton,
dry dry
Poplar 7,775 15.55
Switchgrass 7,929 15.86
Miscanthus 7,900 15.80
Biomass sorghum 7,240 14.48
Pine 6,210 12.42
Eucalyptus 6,185 12.37
Energy cane 7,900 15.80
Municipal Solid Waste
Municipal solid waste (MSW) represents the trash and various items that household,commercial,and
industrial consumers throw away—including materials such as glass, construction and demolition
(C&D) debris,food waste, paper and paperboard, plastics, rubber and leather,textiles,wood, and
yard trimmings. About 25% of MSW is currently recycled, 9% is composted,and 13% is combusted
for energy recovery.And the roughly 50% balance of MSW is landfilled.
ICF limited our consideration to the potential for utilizing MSW that would otherwise be landfilled as a
feedstock for thermal gasification;this excludes MSW that is recycled or directed to waste-to-
energy facilities. ICF also excluded food waste from consideration, as that is covered separately as a
feedstock for RNG production. ICF extracted information from the U.S. DOE Bioenergy KDF,which
includes information collected as part of U.S. DOE's Billion-Ton Study. ICF only considered the waste
residues that were biogenic in origin e.g., paper and paperboard, leather,textiles,wood, and yard
trimmings.
Methanated Hydrogen via P2G
As noted previously,the resource potential for synthetic methane was assumed to be constrained
based on the hydrogen availability for each geography(Oregon and Washington and the United
States).These constraints are discussed in Section 4.2.2.
Synthetic Methane Resource Potential Projection
The following figures summarize the maximum synthetic methane potential for biomass gasification
and via power-to-gas in OR and WA and at the national level. Note that the volumes shown for the
national resource in both instances are scaled in the same manner as described previously as it
relates to RNG: we assumed first mover access yielding a result whereby the Utilities will likely be
able to access up to about 13%of the total domestic RNG production.
CONFIDENTIAL 48 2025 Natural Gas IRP Appendix 284

Exhibit 44. Synthetic Methane via Biomass Gasification Resource Potential Projection (OR& WA and
National)
350
■OR&WA ■National
41
300
m
0
a
c 250
o ..
0 �
m 200
0
L
a g
m
o 150
m E
.v
100
a�
= 50
N
2025 2030 2035 2040 2045 2050
Exhibit 45. Synthetic Methane via P2G Resource Potential Projection (OR& WA, million MMBtu/y)
20
■Wind ■Solar Nuclear
15
m
0
a
c j
o
v 10
3 m
Oa 2
c
,O
_ = 5
U E
0 "
m
s
0
N 2025 2030 2035 2040 2045 2050
CONFIDENTIAL 49 2025 Natural Gas IRP Appendix 285

Exhibit 46. Synthetic Methane via P2G Resource Potential Projection (National, million MMBtu/y)
140
120
■Wind ■Solar ■Nuclear
41
100
4J
0
a
c j 80
0
+� 4J
� m
60
0 g
a c
.1 .2 40
2
U
v 20
j 0
N 2025 2030 2035 2040 2045 2050
Synthetic Methane Levelized Cost
The LCOE for synthetic methane draws from similar data sources as those used in Section 3 and
Section 4 for RNG and hydrogen, respectively. Exhibit 47 below outlines some of the incremental
costs of synthetic methane production from either hydrogen produced via electrolysis or via
biomass gasification. Note that the table excludes the baseline costs of hydrogen production via
electrolysis (i.e.,green and pink hydrogen) because that is discussed in Section 4.
Exhibit 47. ICF Synthetic Methane Assumptions
Cost Parameter ICIF Cost Assumptions
Capital Costs
• Differentiate by syngas feedstock e.g., hydrogen via electrolysis vs
thermal gasification of biomass
Facility Sizing . Prioritize larger facilities to the extent feasible but driven by resource
estimate.
Hydrogen storage • Will vary depending on optimized configuration after considering CO2
availability
CO2 source • Need a CO2 source and may require a separation unit for purity
COz storage • Will vary depending on optimized configuration after considering H2
availability
Compression • Compression required for CO2 prior to methanation
Methanation • Capital costs for methanation equipment
Gas Conditioning and . As needed for syngas prior to methanation
Upgrade
CONFIDENTIAL 50 2025 Natural Gas IRP Appendix 286

Cost Parameter lCF Cost Assumptions
O&M Costs
• Fixed opex costs: Costs for each equipment type for either
methanation after electrolysis or biomass gasification to ensure
Operational Costs operational readiness e.g., methanation, storage
• Variable opex costs: Includes utility costs for electricity and gas
purchases as necessary for electrolysis, methanation, and balance of
plant
• Water costs
Feedstock • CO2 costs for methanation after electrolysis
• Feedstock costs for biomass gasification
Delivery • Operating an interconnect or delivery to utility pipeline injection
Levelized Cost of Gas
• Calculated based on the initial capital costs in Year 1,annual
Project Lifetimes operational costs discounted, and synthetic methane production
discounted accordingly over a 20-year project lifetime,for example.
The potential for decreasing cost of methanation technology consistent with the figure below,
presented in units of $/kW.
Exhibit 48. Projected Methanation Cost Reductions ($/kW)
$400
$350
$300
Y_
$250
0
0
U $200
0
m
@ $150
L
N
$100
$50
$0
2020 2025 2030 2035 2040
Biomass Gasification
The following figures and tables summarize the LCOE for the thermal gasification of biomass in OR
and WA and at the national level. ICF assumed the investment tax credit (ITC)for RNG production
(via the Qualified Biogas Property provisions) is available and extended through 2030 for biomass
gasification.
CONFIDENTIAL 51 2025 Natural Gas IRP Appendix 287

Exhibit 49. Synthetic CH4 from Biomass Levelized Cost Projection Base Case Results ($/MMBtu)
Feedstock • • • •
Biomass, NW and National $17-$44 $22-$57
ICF notes that we observe a difference of less than 5% between the NW and National estimates for
the levelized cost of synthetic methane via biomass gasification.
The impact of the Monte Carlo process on costs for synthetic methane from biomass gasification in
Oregon and Washington and nationally are shown in the figures below for 2030 and 2050,
respectively.The histograms depict the number of the 1,000 Monte Carlo cases (y-axis) that fall
within various cost ranges/technical potential ranges (x-axis)for synthetic methane from biomass
gasification for Oregon and Washington and the United States.
Exhibit 50. Summary of Monte Carlo Simulation Results for Synthetic CH4 from Biomass (2030)
1,600
1,400
1,200
1,000
800
600
400
200
0 ---�
OO NNco CO LO
NNNNNNNNNNNN�� MMMMMMMMMMNMM-qq *,qggq
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Methanated Hydrogen via P2G
The following figures and tables summarize the maximum RING LCOE for each feedstock and
production technology in OR and WA and at the national level. ICF assumed the investment tax
credit(ITC)for RNG production (via the Qualified Biogas Property provisions) is available and
extended through 2030.
Exhibit 51. Synthetic Methane paired with P2G Levelized Cost Projection Base Case Results (Oregon
and Washington, $/MMBtu)
Electricity Source . • • • •
Wind $34-$46 $55-84
Solar $29-$40 $44-61
Nuclear $35-$42 $59-$77
CONFIDENTIAL 52 2025 Natural Gas IRP Appendix 288

Exhibit 52. Synthetic Methane paired with P2G Levelized Cost Projection Base Case Results
(National, $/MMBtu)
Electricity Source for P2G (National)
• • • •
Wind $31-$43 $54-$81
Solar $21-$30 $45-63
Nuclear $35-$43 $58-$77
The impact of the Monte Carlo process on costs for synthetic methane produced from green and
pink hydrogen and various CO2 sources in Oregon and Washington and nationally are shown in the
figures below for 2030 and 2050, respectively.The histograms depict the number of the 1,000
Monte Carlo cases (y-axis)that fall within various cost ranges/technical potential ranges (x-axis)for
synthetic methane produced from green and pink hydrogen and various CO2 sources from each of
the feedstocks considered for Oregon and Washington and the United States.
Exhibit 53. Summary of Monte Carlo Simulation Results for Synthetic CH4 from Methanation of
Hydrogen (2030)
2,000
1,500
1,000
500
0
777 70 Cfl ^ 00 M Q M N M V 70 CO ^ 00 M Q M 7
Efl fig b9 69 8R to Ef} <AP � V). tq {q tq <a « tq 6% q to 64 64 8R
Q � Ln (
N N M � Ld & r- c0 6M CV M n M Q N M
Ef? b9 b9 tq ff} 8R CS! N M M co M M CO CO co M �
ICF found that the cost of CO2 would be a marginal contributor to the overall cost of the system, and
that it would be available at a low cost(e.g., less than $50 per ton).
Synthetic Methane GHG Life Cycle Emissions
ICF evaluated Cis from the synthetic methane feedstocks discussed in this section, using the same
approach outlined previously in Section 3. Synthetic methane production from biogenic sources
requires a series of steps (see figure below): collection of a feedstock, delivery to a processing
facility for biomass-to-gas conversion,gas conditioning,compression and injection into the pipeline
and combustion at the end use.
CONFIDENTIAL 53 2025 Natural Gas IRP Appendix 289

Exhibit 54. LCA Boundary for Synthetic Methane via Biomass Gasification
Lifecycle GHG Emissions Accounting
Combustion GHG Emissions Accounting
+Feedstock Collection +Syngas Processing +Transmission +Combustion
y o o0
T � � RNG
o000
000
Collection&Processing Transmission End-Uses
The table below summarizes the GHG life cycle emissions for synthetic methane production in OR
and WA and at the national level for biomass gasification. ICF notes that the Cl values for biomass
differ slightly between the regional estimate and the national estimate based on changes in the
carbon intensity of electricity. over time in the analysis as a function of assumptions around
decreases in a) the carbon intensity of electricity tied to deployment of renewable energy and b)
slight reductions in the carbon intensity of gas extraction and distribution.
Exhibit 55. RNG Carbon Intensity Projection Base Case Results (kgCO2el MMBtu)
Synthetic Methane Pathway
• •
Biomass Gasification 35-37 39-50
Methanated Hydrogen 3.4— 7.7
CONFIDENTIAL 54 2025 Natural Gas IRP Appendix 290

Renewable Thermal Certificates
The U.S. lacks a national certification program for the environmental attributes of low-carbon fuels
considered in ICF's analysis.While some renewable fuel certification programs exist, such as the
Green-e Renewable Fuels program,they are limited in scope and insufficient for broad market
participation. M-RETS32 offers a North American tracking system for renewable thermal credits or
certificates (RTCs)that can—and does—support the work of certification schemes like Green-e
Renewable Fuels Programs.Today there are about 75-80 RNG facilities registered as RTC generators
with M-RETS,with most generators reporting from landfills;there is a single RTC generator listed that
produces an RTC via hydrogen.
M-RETS facilitates RTC markets by issuing a unique,traceable digital certificate (i.e., one RTC)for
every dekatherm ("dth") of verified renewable energy recorded on the platform.The M-RETS
platform provides more than just the ability to track RNG volumes. M-RETS provides for—but does
not require—the ability to track carbon pathways and Cl values with documentation associated with
each certificate. Once issued, M-RETS users can choose to transfer(buy/sell), retire, import,or
export RECs or RTCs. M-RETS users can retire certificates either to comply with state mandates
and/or to fulfill their voluntary commitments, while preventing the risk of double counting. M-RETS
registers projects in all U.S. states and Canadian provinces and will support imports and exports with
any registry in North America that meets its specific security and operational requirements specific
to the risk of double counting.
M-RETS RTC platform launched January 1, 2020,and shortly thereafter issued the first certificates.
This first-of-its-kind system saw the first ever public sale and claim by a Fortune 50 corporate client
not too long after.33 In 2020,Oregon established the first program that required the use of M-RETS
through Senate Bill 98, under which the Oregon Public Utilities Commission adopted the M-RETS RTC
platform as a compliance tool. California adopted M-RETS as the recognized compliance tool for
implementing Senate Bill 1440 thereafter.34 The California Public Utilities Commission now requires,
"biomethane producers to track injections into the pipelines through the M-RETS platform"as part of
Senate Bill 1440 compliance.35 The applications for the M-RETS RTC registry continue to grow. In
2022, both Oregon and Washington adopted the use of M-RETS to track RNG under their respective
state clean fuel programs.
12 M-RETs is a nonprofit organization governed by an independent and multi-jurisdictional board of
directors.
ss U.S. Gain First to Provide RNG Through New M-RETS RTC Platform,CSRWire,January 30, 2020,
https://www.csrwire.com/press releases/43478-u-s-gain-first-to-provide-rng-through-new-m-
rets-rtc-platform,ACT Commodities and Bluesource complete first renewable thermal transaction
using state-of-the-art tracking tool, M-RETS, February 8, 2021, https://www.mrets.org/act-
commodities-and-bluesource-complete-first-renewable-thermal-transaction-using-state-of-the-
art-tracking-tool/.
14 CPUC Decisions No. 22-02-025 (see pg. 50 of the decision).
sa Order Instituting Rulemaking to Adopt Biomethane Standards and Requirements, Pipeline Open
Access Rules,and Related Enforcement Provisions, Decision Implementing Senate Bill 1440
Biomethane Procurement Program (2022), Cal. P.U.C. Dec. No. 22-02-025 (see pg. 50 of the
decision).
CONFIDENTIAL 55 2025 Natural Gas IRP Appendix 291

Despite progress made by M-RETS and the increased acceptance of RTCs as a market-based
mechanism to acquire the environmental attributes of low-carbon fuels like RNG,the market lacks
liquidity,with lack of transparency on pricing and volumes. However, ICF conversations with
stakeholders indicates that pricing to date has used environmental commodity pricing from the
federal Renewable Fuel Standard (RFS) as a benchmark for contract pricing. Under the RFS, RNG from
most feedstocks is designated as a Cellulosic Biofuel and is designated as a D3 RIN (where RIN is a
Renewable Identification Number). RTC pricing has reportedly traded at a discount to the D3 RIN
price—a price that is reported by various data sources such as OPIS,Argus,and is also reported
publicly by the EPA (albeit with a lag).
Based on information available today, ICF used a forecasting approach for the federal RFS market in a
Reference Case and Downside Case to provide a range of pricing that is indicative of RTC pricing
over the term of the analysis (out to 2050). ICF did not explicitly characterize RTC volumes in the
analysis; however, ICF has indicated that the upper limit of RTCs would be linked to the RNG
(inclusive of the synthetic methane from biomass gasification and from methanated hydrogen via
P2G)that was not incorporated into the supply stacks outlined in Section 3 and Section 5,
respectively.
Overview of ICF Approach to RIN Forecasting
Introduction to the Federal RFS
The RFS mandates biofuel volumes that must be blended into transportation fuel each year.
Specifically,the policy mandates that producers of petroleum fuel products and blenders add
renewable fuels into their pool every year.The program was developed as part of the Energy Policy
Act (EPAct) of 2005 and revised and updated by the Energy Independence and Security Act (EISA)
in 2007. From 2006 to 2022, mandates were codified in legislation. Now the EPA,the program
administrator,determines the volume targets.
Every eligible gallon of renewable fuel is given a Renewable Identification Number or RIN. Among
other things,the RIN identifies who made the fuel,when it was made,and what type of fuel it is. The
RINs can be sold along with the fuel or"separated"and sold to an obligated party(e.g., a petroleum
refinery) separately. Typically,the RIN is sold with the volume of fuel to a blender who then sells the
blended fuel to fuel outlets (e.g., retail gasoline stations). The blender then sells the"separated RIN"
back to the refinery. A diagram is shown in the figure below.
CONFIDENTIAL 56 2025 Natural Gas IRP Appendix 292

Exhibit 56. Illustrative Flow of RIN Generation and Retirement
Renewable a Renewable
fuel Renewable fuel
Renewable Fuel fuel created blended with
ProducerRINs non-renewable fuel BlendedService
generated fuelStation
RINs are separated
due to fuel blending
Non-renewable Non-renewable
• fuel created or .' fuel
imported
RVO* Retired RINs— Purchased RINs are
incurred RVO*fulfilled retired to fulfill RVO*
*RVO=Renewable Volume Obligation
Changes to the program in the EISA created four nested categories, as shown in the table below:
renewable biofuels,advanced biofuels, biomass-based diesel, and cellulosic biofuels. Each category
has its own volume requirement and RIN type. RINs are the currency of the RFS program and are
represented by a 38-digit code representing an ethanol gallon equivalent of fuel. Each category
includes a threshold of life cycle GHG emission savings compared to petroleum products (i.e.,
gasoline and diesel).
Exhibit 57. Nested Categories of Renewable Fuels in the RFS Program
RIN Type D- Biofuel
D3 Cellulosic Biofuel 60%GHG savings Cellulosic,Advanced or
Renewable
D4 Biomass-Based Diesel 50% GHG savings Biomass-Based Diesel,
Advanced or Renewable Diesel
D5 Advanced Biofuel 50% GHG savings Advanced or Renewable
D6 Renewable Fuel 20%GHG savings Renewable (Corn-Based
Ethanol)
Cellulosic or Advanced,
D7 Cellulosic Diesel 60%GHG savings Biomass-Based Diesel, or
Renewable
The nested nature of the biofuel categories in RFS means that any renewable fuel that meets the
requirement for cellulosic biofuels or biomass-based diesel is also valid to satisfy the advanced
biofuels requirement. In other words, if any combination of cellulosic biofuels or biomass-based
diesel exceeded the sub-mandates,the additional supply/volume would count towards the
advanced biofuels mandate,thereby reducing the potential need for fuels (e.g., imported sugarcane
CONFIDENTIAL 57 2025 Natural Gas IRP Appendix 293

ethanol)to meet the unspecified portion of the advanced biofuels mandate. Note that D3 RINs,
however, are not eligible to satisfy D4 obligations.
RIN Price Modeling
The core value of a RIN is determined based on the price-supply relationship and price-demand
relationship for each category of biofuel. Referring to the figure below, as you move along the supply
curve(blue line), producers can charge a higher price, and supply increases. As we move along the
demand curve (red line), higher prices lead to lower demand.At the point where the supply matches
demand (Pe),the system is in balance and has achieved an equilibrium price with equilibrium volume
("Qe").The RFS mandate, however,assumes that the equilibrium price does not yield a sufficient
volume of biofuels, and thereby artificially shifts demand to the right. As demand is shifted the
supply price ("Ps") and demand price("Pd") are no longer in equilibrium.The difference between
these two prices, created as a result of the mandate, leads to the determination of the core or
intrinsic RIN value.
Exhibit 58. Determining Intrinsic RIN Value
Price RFS2
S
PS ----- -----------
RIN core value
i
i
i
d D
i
i
i
i
i
i
Qe Quantity
Source:Figured adjusted from McPhail, Westcott, & Lutman (2011)
This core valuation, however, does not capture market impacts like traders seeking arbitrage
opportunities (e.g., importing sugarcane ethanol at a price advantage) or constraints like physical
blend walls,which limit the quantity of fuel that can be taken up into the market.These types of
phenomena lead to volatility and can run up the price in the RIN markets. Our modeling considers
these phenomena to the extent feasible but predicting these types of spikes requires access to a
large amount of privileged data/information.
The figure below shown below summarizes historical RIN prices across the different RIN types from
2016 to mid-2024.
CONFIDENTIAL 58 2025 Natural Gas IRP Appendix 294

Exhibit 59. Historical D3, D4, D5 and D6 RIN Pricing(nominal), 2016 to mid-2024
Weekly D3,D4,DS and D6 RINs Prices
3 —4 — 5 — 5
$-za
L
$8.00
2816 2817 '018 'P19 2020 2021 2822
Transfer Date by Week FUEL(D Code)
There are several components to ICF's RIN modeling. More specifically,we forecast wholesale
gasoline and diesel pricing,we utilize third-party forecasts for feedstocks that are used to produce
biomass-based diesel and then forecast D4 RIN and D5 RIN pricing based on different market
assumptions. Lastly,we use these variables as inputs into our D3 RIN forecast.
Wholesale petroleum product pricing. ICF uses an internal WTI forecast that reflects the long-term
marginal cost of oil extraction,with short-term adjustments based on NYMEX futures and the Short-
Term Energy Outlook("STEO") published by the EIA.We use historical crack spreads for gasoline and
diesel pricing forecasts,with near-term adjustments made based on market observations.
Soybean oil pricing. Soybean oil is the primary feedstock used for biomass-based diesel
production—including biodiesel and renewable diesel. We use renewable oil feedstock(e.g.,soybean
oil) pricing provided by Euromoney Global Limited,d/b/a Fastmarkets,The Jacobsen ("Jacobsen").
The information provided by The Jacobsen is cross-referenced to other publicly available resources
for consistency of market sentiment. Soybean oil is a primary input into the biodiesel and renewable
diesel production process, and other fats and oils are often indexed to soybean oil pricing.
Corn Pricing. Corn is the primary feedstock used for ethanol production. We use corn pricing from
the USDA for our ethanol production costs.
D6 RIN pricing. ICF models the D6 RIN price assuming the EPA sets the Renewable Fuels RVOs at 15
billion gallons.This volume is expected to remain well above the blend wall. We do not model
increasing gasoline demand; rather,we model decreasing gasoline demand domestically due to
increased efficiency(or improved fuel economy)for internal combustion engine vehicles and
increased sales of electric vehicles. Decreasing gasoline demand yields a persistent gap (on the
order of 1 billion gallons) between demand and required supply at the 15 billion gallon level.This
modeled gap continues to keep D6 RINs tightly linked to D4-D5 RIN pricing, as the market looks to
D4 RINs and/or D5 RINs to close the compliance gap at the margin and support D6 RIN pricing well
above the perceived floor value of ethanol as an oxygenator(which is somewhere around 10 cpg).
CONFIDENTIAL 59 2025 Natural Gas IRP Appendix 295

Ethanol has inherent value as an oxygenator due to the Clean Air Act of 1990 which specified a
certain amount of oxygen be added to gasoline. Because of this,we expect E10 blends to persist
regardless of D6 RIN prices. If the EPA were to set RVOs at or below the E10"blend wall", little or no
incentive would be required to bring these fuels to market. However, in this case,we believe the D6
RIN would retain some value. Historically the value of ethanol as an oxygenator has been in the range
of 10-15 cpg. During compliance years 2011-2012,this price dynamic persisted as ethanol blend rate
growth outpaced the blend rates implied by the RVOs.We consider this to be a lower bound for the
D6 RIN price.
D4 RIN pricing. We model D4 RIN pricing by assuming that the marginal unit of compliance is
achieved by blending biodiesel into the market.We consider biodiesel the marginal producer due to
the amount of biodiesel sold into non-LCFS markets.This requires marginal biodiesel producers to
recover more costs from the RFS program compared to other fuels (e.g., renewable diesel,which is
almost entirely consumed in California), ultimately driving the RIN price.
D4 RIN prices generally find support from a historical market-based correlation with the bean oil-
heating oil ("BOHO") spread. More specifically,elevated biodiesel production economics, as
measured by the BOHO spread, drives the need for higher D4 RIN pricing to incentivize blending
more expensive biomass-based biodiesel into conventional diesel.With respect to D4 RIN pricing,
we assume that ULSD blended with biodiesel and unblended ULSD are effectively perfect
substitutes,after adjusting for biodiesel's lower energy content(about 93%the energy content of
ULSD). Because biodiesel is more expensive than ULSD, it would not enter the market were it not for
D4 RIN prices (and other subsidies e.g.,the BTC).We use the BOHO spread as a first-order
approximation of the D4 RIN, after accounting for the"expectation" of the BTC subsidy.The graph
below shows the base model of the D4 RIN weekly average price versus the BOHO spread.
Exhibit 60. D4 RIN Pricing vs. BOHO Spread
250
200
a 150
z •
0 100 .�
50
0
-100 -50 0 50 100 150 200 250
BOHO Spread (cpg)
Our D4 RIN forecasting also includes current BTC and IRA considerations, including the retroactive
extension of the BTC to eligible producers and the creation of the section 45Z Clean Fuels
Production Tax Credit ("CFPC").These tax credits contribute to the renewable fuel value stack and
place downward pressure on RIN prices. Because the CFPC is carbon intensity dependent,we
CONFIDENTIAL 60 2025 Natural Gas IRP Appendix 296

assume that marginal producers will have a Cl of 35 kgCO2e/MMBtu which results in about
$0.30/gallon in value.
D5 RIN pricing.We assume that D5 RIN pricing is at parity with D4 RIN pricing. In other words,we
assume that biodiesel from soybean oil is the marginal unit of compliance used to satisfy the D5 RIN
obligations.
CWC Pricing. The CWC is calculated based on the formula in the regulation,which is the greater of
$0.25 or$3.00 minus Pgasoline,where Pgasoline is the average wholesale price of gasoline ("RBOB"). Both
constants in the formula, $0.25 and $3.00, are adjusted for inflation from January 2009 (per the
regulation)to June of the year in question.
D3 RIN pricing. Historically, D3 RIN pricing has tracked closely to the sum of the D5 RIN and the value
of the Cellulosic Waiver Credit(CWC). However, EPA opted not to use its waiver authority during the
promulgation of the Set Rule in 2023,which saw EPA set RVOs for 2023, 2024, and 2025. EPA
posited that they could not use the waiver authority and set authority coincidentally.The EPA,
however, explicitly noted that they retain their waiver authority.
In the absence of the CWC,we assume that the D3 RIN price will be set by market fundamentals i.e.,
that the D3 RIN price will be set by a marginal producer that looks to the D3 RIN value to cover
production costs and make a rate of return.
The difficulty with using a supply and demand model to forecast the D3 RIN price is twofold:
• RNG supply to the transportation market(for RIN generation) is opaque because the fuel can be
sold into multiple end use markets. It is possible that an RNG producer selling into the
transportation market in year X may sell into a different market in year X+1.As a result,the RNG
supply curve is more nuanced than in previous years and increases uncertainty in our modeling.
• Calculating production costs for specific RNG facilities is challenging. For fuels like ethanol and
renewable diesel,feedstock costs represent such a large percentage of production costs that
they are a good indicator of current and future production economics. RNG production costs,
however, are tied to bespoke operating conditions and varying capital expenditures and their
associated financing assumptions.This makes it difficult to estimate the costs of RNG volumes
coming into the transportation market, and the corresponding subsidy(e.g.,the D3 RIN price)
required for market clearance.
ICF currently uses the sum of our forecasted D5 RIN price and calculated CWC value as an indicator
for D3 RIN price forecasts.We often use a market-based discount factor, represented in our
modeling as alpha.
PIN Banking Dynamics. The regulation allows for a maximum 20% carryover of RINs from one year to
the next,which means that a maximum of 20% of a regulated party's obligation in year X+1 can be
met using RINs with vintage year X.We assumed that the 20% carryover of RINs is unchanged over
the term of our modeling.
ICF RIN Price Outlook
ICF's RIN pricing outlook for D5 RINs (blue line) and D3 RINs (yellow line) is shown in the figures below
for the Reference Case and Downside Case.
CONFIDENTIAL 61 2025 Natural Gas IRP Appendix 297

Exhibit 61. ICF's RIN Price Forecast, Reference Case (nominal dollars)
$3.5
$3.0
z $2.5
E2
i.q $2.0
m
$1.5 /�"♦ i�
o / ♦�� ��•.�..�---------
Z $1.0 /
$0.5
$0.0
�01�01�0 �01�01�0V rp 61-�ory 'V O-'O'�Or�6V (3T,65�O�rO�'O�'O�rO�'f��O��O��O�r10�0
D3-Historical D5-Historical——— D5 Forecast-Reference——— D3 Forecast-Reference
Exhibit 62. ICF's RIN Price Forecast, Downside Case (nominal dollars)
$3.5
$3.0
Z $2.5
4.4 $2.0 —
7
$1.5
♦ --- ---
$0.5
$0.0 —
01h&b&A(P 0•&Q, �O 0r1 co, r`' �D �h ��O �� �4� �� 11O Co' `!� 33 3� 3� �0 3A 3�
T T T T rO r, 'O rO 'O 'O 'O rO rO rO 'O r, 'O 'O rip 'O �O 'O 'O 'P �O
D3-Historical D5-Historical ——— D5 Forecast-Downside D3 Forecast-Downside
Note on D3 RIN Pricing
The announcement of the proposed partial waiver of the 2024 D3 RVO resulted in the first major
shift in the D3 RIN market since the Set Rule in June 2023. In the proposed ruling,the EPA estimated
that D3 RIN production in 2024 will be short of the 1.09 billion gallon RVO,suggesting the revised RVO
will be 0.88 billion gallons. However,the EPA has indicated that it will ultimately set RVOs for 2024 at
actual 2024 RIN generation, minus the 2023 carry-over deficits, meaning RIN supply and demand will
be equal.
D3 RIN prices have been trading at an average of$2.30/RIN since the release of the proposed waiver,
albeit likely at low trading volumes.With D4 RIN and D5 RIN spot prices at an average of$0.67/RIN in
Q4 and a theoretical Cellulosic Waiver Credit value at roughly$1.63 in 2024, current pricing mirrors
the CWC + D5 RIN pricing paradigm,which would be at $2.30 per RIN.While the EPA did not explicitly
mention the use of the CWC,the EPA did note in their proposed ruling that they are seeking
CONFIDENTIAL 62 2025 Natural Gas IRP Appendix 298

comment from market participants regarding the use of the cellulosic waiver as opposed to a
general waiver. As such, it's a possibility the EPA administers the CWC for 2024.
It is also possible a similar situation occurs in 2025. In the previous update ICF covered the gap
between CNG dispensing demand and the 2025 RVOs. ICF's estimates suggest that to hit the 2025
RVO, CNG dispensing capacity would need to increase, implying an increase in the use of CNG as a
transportation fuel, an uncertain outcome.Accordingly, ICF has adjusted its 2025 forecast to reflect
the expectation that the market will produce insufficient D3 RINs and another volume waiver from
the EPA will be issued. Previously we forecasted the D3 RIN pricing assuming that the undersupply
continued without regulatory intervention,thus current forecasted D3 RIN prices for 2025 are down
from the last update.
Beyond 2025, ICF's forecasts have risen from the previous update. Due to ICF's model methodology,
the D3 RIN price is reacting to the upward change in D5 RIN economics, driven by long-term soybean
oil outlooks. Given the potential limitations on dispensing in coming years and the significant
demand pull from non-transportation markets,the forecasted prices in the range of $2.84-$3.42/RIN
is justifiable.
RIN Prices as a Proxy for RTC Pricing
ICF used the forecasted D3 RIN pricing outlined previously to develop a range of pricing that will
likely be used for RTC benchmarking for the foreseeable future. Presumably,as RNG demand in the
non-transportation sector(e.g.,for Utilities) increases significantly above RNG demand for on-road
transportation,the D3 RIN will no longer serve as predictive benchmark. However,the D3 RIN pricing
shown is consistent with moderate pricing observed in the RNG supply curves and may be reflective
of where pricing will fall in the mid- to long-term future.
Exhibit 63. ICF Estimated Pricing Range for RTCs ($/mm8tu)
$40
■ RTC Pricing, Range
$35
pp $30
E
E $25
D $20
C
U $15
d
U $10
$5
$0
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041
CONFIDENTIAL 63 2025 Natural Gas IRP Appendix 299

Carbon Capture, Use, and Storage
One of the carbon mitigation options included in the analysis is carbon capture, use,and storage
(CCUS).The first step in this process is to capture the CO2 from various possibles sources including:
• Flue gases of power plants and industrial facilities burning fossil fuels or biomass/biofuel,
• Process gas streams from industrial facilities (natural gas processing plants, ammonia plants,
methanol plants, petroleum refineries, steel mills,cement plants, ethanol plants,etc.)
• Hydrogen plants using fossil fuels or biomass as feedstocks
• Air(through the application of direct air capture).
After capturing CO2,the next steps typically are to purify and dehydrate the CO2,compress it for
transportation and then either(a) to inject it underground into an appropriate geological storage site,
where it is trapped and permanently stored in porous rock or(b) utilize it in one or more of the ways
shown in the chart below in Exhibit 64.
Exhibit 64. Options for CO2 Utilization (via NETQ
r url, rn,.d IMurnwcewia.l
Addili—
Algae
Carbonated Beverages BIs'gs
i Greenhouse Gases
_ _ flawrs'fragrances
- Dccaffeinatioo -
a ldnsg
hoducts
Compcosed Gas Energy Sturagc -el
ces Chemical Energy Storage <v'
Heal iramirr World fluid 1 ,s�se Carbonates
qd d
Fih
Mnedn"
OR Foot Enhanced (hrmils Urea fertiRrer
Gas I url eerosary Co
ECBM Metlsore
1
SecoMAry
Chemicals
��rRate ,_� t `c '�� Retngeration
r Dry Ice
r
FE NFiE C%Utilization Fre Etlinguishers Blanket Producb Injected into Metal Castings
Supported Area Protect Reactive Powders Added to Medical O:as lt"piralwy Stimulant
-------------- Shirld Gas in Wilding Aerosol Can Propellant
Ory Ice Pellets Used for Sand Blasting
Red Mud Carbonation
Source.National Energy Technology Laboratory wivw.ned.doe.g-
CONFIDENTIAL 64 2025 Natural Gas IRP Appendix 300

Carbon Capture Costs
There are many technologies available to capture CO2 from flue gas and process gas streams
including several kinds of post-combustion capture (e.g.,absorption by chemical solvents,
adsorption by solid sorbents, membrane separation, cryogenic separation,and pressure swing
adsorption).The major competitor to post-combustion technologies is oxy-fuel combustion in
which pure oxygen combustion air is used to produce a nitrogen-free flue gas that can be
transported and stored after relatively inexpensive dehydration and treatment steps.The main
drawback to oxy-firing is the large amounts of energy use and high cost associated with separating
oxygen from air.
The economic modeling of carbon capture costs for this analysis is based on post-combustion
capture by absorption by chemical solvents.This is the most mature and widely used process.The
basis is for the cost estimates is the Global CCS Institute's (GCCSI) March 2021 report entitled
"Technology Readiness and Costs of CCS." Capture costs were modelled as largely a function of CO2
partial pressure36 and the volume of CO2 being captured.The GCCSI cost estimate was based on an
aqueous solution of 30% by weight of monoethanolamine(MEA). MEA is a chemical solvent that has
wide commercial availability and performs well over a range of CO2 partial pressures.
The cost of capturing CO2 as calculated by GCCSI is shown in Exhibit 65 in units of dollars per metric
ton of captured CO2.These costs include annualized capital costs,operating and maintenance cost,
costs for consumables, and energy costs.The exhibit indicates that high-volume gas streams with
high CO2 partial pressures can be captured at a cost of under$50/MT of CO2,while gas stream gas
with lower partial pressures and/or smaller stream volumes will have higher capture costs of$50 to
$100/MT of CO2 or more.
36 Partial pressure is measured as the percent concentration of CO2(or any other gas) in a gas
stream times the pressure of that gas stream.A gas stream with high partial pressure of CO2 means
that it will be easier and less expensive to capture the CO2 because less external energy is required
compared to streams with lower CO2 concentrations and/or lower pressures.
CONFIDENTIAL 65 2025 Natural Gas IRP Appendix 301

Exhibit 65. CO2 Capture Cost from Industrial and Power Plant Flue Gas and Process Gas Streams
300
COST DIFFERENCE AT VARIOUS SCALE OF PLANT
• COST AT MAXIMUM STUDIED SIZE OF CAPTURE PLANT
250
U
0
s=
0
200
0_
o
t
to
150
Q
ra
U 100
0
-2
50 �-
o •_..__�_...._�._.__�.._..�
U
CO2 Partial Pressure in Flue Gas(kPa)
0
1 2 3 4 5 6 8 'D 12 14 18 22 26 30 35 41
Aluminium Smelting: Petroleum Coke/ Cement Kiln Plant:
0.02 to 0.2 Mtpa CO, Natural Gas Power 0.18 to 1.8 Mtpa CO,
Captured Plant:0.12 to 1.2 Mtpa Captured
CO2 Captured
Steel Plant Dedusting NGCC/Steel Sinter Biomass Power Plant: Coal Power Plant: Steel Hot Stove Plant:Steel COFfX Plant:
Chimney:0.04 to 0.4 Plant:0.07 to 0.66 0.13 to 1.3 Mtpa CO, 0.15 to 1.5 Mtpa CO, 0.2 to 2.0 Wes CO, 0.2 to 2.0 Mtpa CO,
Mtpa CO,Captured Mtpa CO,Captured Captured Captured Captured Captured
Source: GCCSI. Costs are for capture only and exclude dehydration and compression,
transportation, and geologic storage. The costs shown above are only to capture the CO2 and do not
include costs for dehydration, compression,transport,and storage. GCCSI also estimated these as
shown below in Exhibit 66. Costs after the capture step will add an additional $16 to $69 per metric
ton of stored carbon dioxide.This brings total CCS cost for large volume industrial and power
combustion flue gas streams and industrial process gas streams to $60 to $150 per MT per GCCSI
estimates.
Exhibit 66. CO2 Compression, Dehydration, Transport and Storage Costs as Estimated by GCCSI
CCS Costs to be Added to Capture Costs ($/metric ton)
Step Low High Middle
Compression & Dehydration $10.00 $22.50 $16.25
Pipeline Transport 300km $2.50 $24.00 $13.25
Injection& Geologic Storage $2.00 $18.00 $10.00
Monitoring & Verification $2.00 $4.00 $3.00
Sum $16.50 $68.50 $42.50
Source: GCCSI
Geologic Storage Capacity
Exhibit 67 shows that the estimated geologic storage capacity in the Lower 48 state sums to 8,215
billion metric tons of carbon dioxide.The capacity estimated for the state of Oregon 33.15 gigatons
(that is 33.15 x 101 metric tons) and for the state of Washington,176.18 gigatons.
CONFIDENTIAL 66 2025 Natural Gas IRP Appendix 302

These storage capacity estimates were derived by ICF from the most recent DOE analysis of the
lower-48 states CO2 sequestration capacities from the"Carbon Sequestration Atlas of the United
States and Canada Version 5."37 The analysis of storage volumes is conducted by regional carbon
sequestration partnerships as overseen by NETL in Morgantown,West Virginia. State level onshore
and offshore capacity volumes are reported for storage in oil and gas reservoirs and deep saline
formations.The vast majority of storage volume is in deep saline formations,which are present in
many states and in most states with oil and gas production. In the most recent version of the Atlas,
offshore storage volumes have also been broken out by DOE into the Gulf of Mexico,Atlantic,and
Pacific Outer Continental Shelf(OCS) regions. ICF conducted a separate analysis to break out CO2
FOR storage potential from the total potential in oil and gas reservoirs reported in NATCARB.
Geologic Storage Costs
ICF has computed geologic storage costs in terms of levelized38 dollars per metric ton of stored CO2.
These costs are largely a function of the geologic characteristics of each project and assumptions
used in the costing algorithms for individual construction and operating components of geologic
sequestration of CO2.The largest economic drivers are the costs of well operation, injection and
monitoring well construction costs, and the costs of site monitoring. Depending on the nature of
each cost element,"unit costs" are specified as dollars per storage site, dollars per square mile,
dollars per foot as a function of well depth,dollars per labor hour, or other kinds of specifications or
algorithms.The unit cost specification module includes data and assumptions for about 105 cost
elements falling within the following ten general cost categories:
• Geologic Site Characterization
• Area of Review(AoR) Study& Corrective Action
• Injection Well Construction
• Operation of Injection Wells & Pumps
• Water Management Capex&Opex
• Monitoring& Reporting Capex and Opex, includes mechanical integrity tests (MIT)
• Financial Responsibility
• Post-Injection Site Care & Site Closure
• General &Administrative Costs
The weighted average geologic storage cost for saline aquifers in the Lower 48 is $16.70 per metric
ton, computed on a levelized basis.
37 See https://www.netl.doe.gov/coal/carbon-storage/strategic-program-support/natcarb-atlas
sa In mathematical terms,the levelized cost produces a net present value of cash inflows (discounted
at the operator's weighted average cost of capital)that exactly equals the net present value of cash
outflows (also discounted at the operator's weighted average cost of capital).
CONFIDENTIAL 67 2025 Natural Gas IRP Appendix 303

Exhibit 67. Geologic Storage Capacity by State
NATCARB US Geologic Storage Capacity Allocated to States(gigatons)
FOR CO2 Depleted Oil Unmineable Saline Sum of All
Storage Fields Coal Aquifers-Non Types
Basalt
Alabama 0.07 0.02 2.98 307.34 310.41
Arizona - - - 0.42 0.42
Arkansas 0.08 0.10 2.46 21.20 23.84
Atlantic Offshore - - - 202.00 202.00
California Onshore 1.24 3.61 - 147.55 152.40
Colorado 0.20 2.15 0.65 131.11 134.11
Delaware - - - 0.04 0.04
Florida 0.13 0.03 1.95 246.45 248.56
Georgia - - 0.02 148.70 148.72
Idaho - - - 0.15 0.15
Illinois 0.10 0.10 2.38 80.75 83.33
Indiana 0.02 0.02 0.14 66.67 66.85
Iowa - - 0.01 - 0.01
Kansas 0.41 0.84 - 34.40 35.65
Kentucky 0.01 1.74 0.18 46.43 48.36
LA Onshore 1.36 4.35 12.89 734.55 753.14
LA.Offshore 1.46 12.70 - 1,240.00 1,254.16
Maryland - - 1.88 1.88
Michigan 0.08 0.18 45.56 45.82
Minnesota - - - - -
Mississippi 0.13 0.32 8.46 459.15 468.06
Missouri - - 0.01 0.10 0.11
Montana 0.25 0.13 0.33 335.74 336.45
North Carolina - - - 6.51 6.51
North Dakota 0.32 0.59 0.54 136.50 137.95
Nebraska 0.02 1 0.01 - 54.47 54.50
Nevada - - - -
New England States
New Jersey - - - - -
New Mexico 0.90 8.81 0.16 129.29 139.16
New York - 0.08 - 4.37 4.45
Ohio 1.08 0.12 9.91 11.11
Oklahoma 1.41 2.99 0.01 76.87 81.28
Oregon - - - 33.15 33.15
Pacific Offshore 0.05 2.63 37.00 39.68
Pennsylvania 1.34 0.27 17.34 18.95
South Carolina - - 31.07 31.07
South Dakota 7.04 7.04
Tennessee - - 1.85 1.85
Texas Onshore 7.55 130.05 21.80 1,505.79 1,665.19
Texas Offshore - 2.97 - 798.00 800.97
Utah 0.28 2.11 0.07 88.65 91.11
Virginia - 0.01 0.37 0.86 1.24
Washington - 0.92 175.26 176.18
West Virginia 9.84 0.37 11.19 21.40
Wisconsin - - - -
Wyoming 0.42 0.17 6.64 570.92 578.15
Lower 48 US Sum 16.45 186.38 66.36 7,946.23 8,215.41
Source:Adapted from the U.S.DOE NATCARB database.
CONFIDENTIAL 68 2025 Natural Gas IRP Appendix 304

Treatment of Tax Credits
Under the Inflation Reduction Act (IRA),the 45Q tax credit was raised to $60/metric ton for carbon
dioxide used in enhanced oil recovery or other industrial operations and to $85/metric for
permanently stored CO2 such as in saline aquifers or abandoned oil and gas fields.The CCUS credit
is available for CCUS projects beginning construction before January 1, 2033, and is to be applied to
CO2 quantities stored in the first 12 years of a project's operation.
The output of the cost analysis is the before-tax-credit dollar per metric ton levelized cost for
capture,transport and storage.Also provided in a second column is the levelized cost after the tax
credit is applied (the tax credit is applied on a levelized basis).That is,the 12 years of credits is
spread over the 20 operating years each CCUS project is expected to have. Under that calculation
the$85/MT credit becomes $58.70/MT on a levelized basis.
The Difference between the Gross and Net GHGs from CCUS
Because the processes of capturing, dehydrating, compressing,transporting and storing carbon
dioxide requires energy,the net effect of capturing and storing 1 metric ton of CO2 is NOT -1 CO2e
metric ton.This is because their GHG emissions associated with additional energy(primarily natural
gas and electricity) is needed to operate the CCUS facilities.The amount of net GHG benefit for each
ton appears in the Output tables in the cells labeled "GHG Emissions". On average this the net benefit
is about -0.93 CO2e per metric ton captured and stored.
Estimating Potential Capture Volumes
The analysis of the potential capture volumes was conducted for each of the three utilities based on
a list of the largest customers in their respective service territories. Data provided by the utilities
included volume of gas sales and the classification of the customers by industry type.The potential
CCUS customers were divided into the eight size classes shown below.The industry classification
was used to develop approximate values for the average partial pressures (an important parameter
in the cost estimation)for each grouping.
• under 25MMBtu/hour
• 25-50MMBtu/hour
• 50-100MMBtu/hour
• 100-200MMBtu/hour
• 200-400MMBtu/hour
• 400-800MMBtu/hour
• 800-1600MMBtu/hour
• 1600+MMBtu/hour
The potential volumes that could be captured are computed assuming a 90% capture rate. For
modeling purposes, it is assumed that the facilities in the utility company customer databases (or
other facilities with similar characteristics)will continue to operate throughout the forecast period to
2050.
CO2 Transportation
ICF's costs of pipeline transportation are based on standard engineering calculations for what
diameter of pipeline is needed to transport a given volume of CO2 and certain assumptions about
how CO2 volumes from individual power plants and other sources get aggregated into larger
CONFIDENTIAL 69 2025 Natural Gas IRP Appendix 305

pipelines for long-distance, inter-regional transportation.The capital cost of the CO2 pipelines is
represented in the ICF cost model in terms of dollars per inch-mile as shown in the tariff rate is
calculated using standard discounted cash flow techniques given these capital costs plus some
assumptions about operating and maintenance costs for the CO2 pipelines.
Exhibit 68. CO2 Pipeline Costs
CARBON DIOXIDE PIPELINES(transported in dense phase at operating pressure of
. • • to 2,200 .
Outside Inside Wall Pipeline CO2 Flo Pipeline Pump Cost of
Inches Inches Inches $/Inch- (metric for 75 for •
Mile tons/da Miles Miles miles
••' ($/metric
•
4 3.2 0.4 $169,919 316 $51.0 $0.1 $58.37
6 5.2 0.4 $181,338 1,074 $81.6 $0.3 $27.71
8 7.2 0.4 $189,901 2,439 $113.9 $0.8 $17.17
10 9.2 0.4 $196,821 4,527 $147.6 $1.5 $12.08
12.75 12.0 0.4 $203,785 8,762 $194.9 $2.8 $8.35
16 15.0 0.5 $215,428 15,563 $258.5 $5.0 $6.32
24 22.5 0.7 $237,863 43,412 $428.2 $14.0 $3.89
30 28.2 0.9 $246,383 76,347 $554.4 $24.7 $2.96
36 33.8 1.1 $254,903 121,093 I $688.2 $39.2 $2.39
42 39.4 1.3 $263,422 178,853 $829.8 $57.9 $2.01
For small volumes of CO2, it might be more cost effective to transport the CO2 by truck.As shown in
Exhibit 69,trucking cost for 25 to 75 miles are $20 to $60 per metric ton for volumes above 50
metric tons per day.
CONFIDENTIAL 70 2025 Natural Gas IRP Appendix 306

Exhibit 69. CO2 Transport Costs, Pipeline versus Truck
CO2 Transportation Costs: Pipeline vs Truck
$1,000
_
$100
o
U
d
E
$10
$1
1 10 100 1,000 10,000
metric tons per day capacity
P/L miles=25 P/L miles=50 P/L miles=75
Truck miles=25 Truck miles=50 Truck miles=75
Use of Stochastic Variables for the CCUS Cost Analysis
There were no stochastic variables created specifically for CCUS. Instead,the cost analysis for CCUS
employed several of the global stochastic variables used in the other techno-economic models.
These include:
• The price of crude oil and diesel fuel (these affected the cost of drilling CO2 storage wells and the
cost of truck transportation of CO2).
• Natural gas prices (these affected the cost of the amine capture process).
• Industrial electricity prices (these impacted the costs for capture, dehydration and compression,
and pipeline transportation of CO2)
• Various indices such as those for well drilling cost, industrial facility construction,cost of capital,
etc.
Cost Results for Base Case
The cost results under base case assumptions are shown in Exhibit 70 for various sizes of facilities
(e.g., industrial plants, powers plant or large commercial/educational facilities) for the year 2030.
Similar information for the year 2050 is shown in Exhibit 71. All of these cases are for a 90% capture
rate and geologic storage at $10/MT.The costs are before any consideration of 45Q tax credit which
would reduce the levelized cost by$58.70 per metric ton.
CONFIDENTIAL 71 2025 Natural Gas IRP Appendix 307

Exhibit 70. CCUS Cost for Base Case Assumptions (2030)
CCUS Cost Results for Base Case Assumptions for Year:2030
Resource Distonceto CO2 Partial Fraction Capital Annual O&M+ Total Cost Dehydration& Sum All CCS Costs
Subcategory or Storage Sito Storage Type Pressure CO2 Annual Capacity Costs Energy Costs ($IMT ofCO2 Compression Trans Mode Transport($IMT) Storage($IMT) ($IMT,betore 450
step (riles) (psll Captured Utilization Rats ($million) ($rilllon) captured) ($/MT) tax credit))
under 25MMBW/hr 50 Geologic,Acquiter,
Medium InjecNity 0.882 90.0% 81.2% $2.49 $0.63 $117.97 $19.75 Truck $64.55 $10.00 $212.26
25-50MMBWIhr 50 Geologic,Acquifer,
Medium Injectivity 0.882 90.0% 62.7°/ $3.08 $0.67 $128.55 $21.72 Truck $42.16 $10.00 $202.44
50-1001AMBuft 50 Geologic,Acquifer,
Medium IniecWiN I 0.882 90.0%1 43.9% $3S6i $0.67 $15535 $26.161 Truck $42.16 1 $10.00 $234.07
100-200MMBW/hr 50 Geologic,Acquifer,
Medium Injectvii1y 0.882 90.0% 53.61/6 $8.34 $1.40 $97.73 $20.27 Truck WAS $10.00 $170.16
200-400MMBW/hr 50 Geologic,Acquiter,
Medium rpcbvity 0.882 90.0% 70.1% $14.31 $2.77 $72.19 $16.93 Truck $36.57 $10.00 $135.69
400-800MME11l 50 Geologic,Acquil
Medium Injectvily 0.882 90.0% 85.0% $37.88 $9.33 $55.90 $15.12 Pipeline $22.89 $10.00 $103.91
800-1600MMBWIhr 50 Geologic,Acquifer,
Medium Injectivity 0.882 90.0% 75.0% $59.67 $14.411 $55.72 $15.93 Pipeline $16.99 $10.00 $98.64
1600+MMBWIhr 50 Geologic,Acquifer,
Medium Injectvity 0.8821 90.0%1 75.0% $103.901 $27.69 $52.34 $15.88 Pipeline $11.80 $10.00 $90.03
DiredAir Capture 50 Geologic,Acquifer,
Medium lnectiv I= 85.0% $1,836.76 $116.97 $593.231 Pipeline $16.07 $10.00 $619.30
Note: Cost are in 2022 dollars.
Exhibit 71- CCUS Cost for Base Case Assumptions (2050)
CCUS Cost Results for Base Case Assumptions for Year:2050
Resource DistonceW CO2 Partial Fraction Annual Capacity Capital Annual O&M+ Total Cost Dehydration& Sum All CCS Costs
Subcategory or Storage Site Storage Type Pressure CO2 Costs Energy Costs ($/MT ofCO2 Compression Trans Mode Transport($IMT) Storage($/MT) ($/MT,before 450
Stop (riles) (psi) Captured Utilization Rats ($million) ($million) captured) ($/MT) tsx credit)
under 25MMBW/hr 50 Geologic,Aoquiii
Medium Injeclivily 0.882 90.0% 811% $2.73 $0.67 $125.29 $23.31 Truck $64.55 $10.00 $223.15
25-50MMBWIhr 50 Geologic,Acquifer,
Medium Injecirvily 0.882 90.0% 623% $3.37 $0.70 $136.88 $25.96 Truck $42.16 $10.00 $215.01
50-100MMBW/hr 50 Geologic,Acquifer,
Medium Injecirvily 1 0.882 90.0%1 43.9% $4.001 $0.71 $166.08 $31.66 Truck $42.16 $10.00 1 $249.91
100-200MMBWmr 50 Geologic,Acquifer,
Medium In ectiv' 0.882 90.0% 53.6% $9.12 $1.50 $105.59 $25.01 Truck $42.16 $10.00 $182.77
200-400MMBWmr 50 Geologic,Acquifer,
Medium In ectiv' 0.882 90.0% 70.1% $15A5 $3.00 $78A1 $20.86 Truck $36.57 $10.00 $145.84
400-800MMBW/hr 50 Geologic,Acquifer,
Mecum In ectivk 0.882 90.0% 85.0% $41.44 $10.16 $60.95 $18.58 Pipeline $2730 $10.00 $117.23
800-1600MMBWIhr 50 Geologic,Acquifer,
Medium lnectiv� 0.882 90.0% 75.0% $65.27 $15.72 $60.80 $19.66 Pi elme $20.52 $10.00 $111.01
1600+MMBWIhr 50 Geologic,Acquifer,
Medium In ectiv 0.882 90.0% 75.0% $113.64 $30.21 $57.14 $19.64 Pipeline $14.24 $10.00 $101.01
DirectNr Capture 50 Geologic,Acquiter,
Medium In ecOv' $5.0% $1,360.71 $93.19 $454.87 Pipeline $19AI $10.00 $484.28
Note:Cost are in 2022 dollars.
The impact of the Monte Carlo process on costs is illustrate in Exhibit 72.The histogram depicts the
number of the 1,000 Monte Carlo cases (y-axis)that fall within various cost ranges (x-axis)for
capture and geologic storage of facilities in the 400-800 MMBtu/hr.size class.This distribution of
cost has a mean of$119.10/MT of CO2 and a standard deviation of$5.19/MT of CO2.
Exhibit 72. Histogram on CCUS Costs Size 400-800MMBtu/hr. for 2050
160
140
170
100
80
60
40
20
0
1p3g51 ,Oh-1\ ,o�55N 1�351 ,,,N51 1,,�gS\ �,A�SN ,,655N 1,�'51 1v0N5N ,2,qS" ,23.0\ 12�55' ,2'Ag5N 12'NSN ,��y51 1�,L�SI 551
N1q.L15, 11p3g5, 11oS15, """011, 95, p15' \,,bs5' a35, k,Zq�S, 112,g5• `12315• 555� 112�g5, "'eO•
CONFIDENTIAL 72 2025 Natural Gas IRP Appendix 308

Caveats and Uncertainties
The cost and volume estimate presented here are based on good-quality data and employ reasoned
judgement. However,there are many uncertainties that should be considered in using these results:
• CCUS is not a mature industry so practices and costs can only be estimated based on current
knowledge regarding similar products and services.
• There is a potential that technological advances for carbon captured could reduce cost below the
amine process that forms the basis for the capture economics shown here.
• The economics of capture can be affected by a large number of site-specific factors such as the
dispersion of sources of flue/process gas sources, contaminants in those gases and available
space for capture equipment.
• Public opposition to CCUS may make it difficult and expensive to site geologic storage projects.
• The potential volumes for CCUS were estimated using databases of large customers as of 2023
and early 2024.The specific facilities contained in those databases might not continue to operate
or use energy in the same manner over the full forecast period.Also, new facilities might begin
operation in the forecast period.
CONFIDENTIAL 73 2025 Natural Gas IRP Appendix 309

Carbon Intensity Modelling
ICF evaluated representative carbon intensities of low carbon fuels using(1)the latest version of
Greenhouse gases, Regulated Emissions, and Energy use in Technologies (GREET) model,developed
by the Argonne National Laboratory(ANL)39, R&D GREET 2023 (Revl), and (2)Tier 1 simplified
calculators for biomethane derived from the OR-GREET 3.0,which are used for Oregon's Clean Fuels
Program (CFP).
While state version of GREET models (e.g. CA- or OR-GREET) are widely seen as a benchmark for
RING carbon intensity values, since Low Carbon Fuel Standards (LCFS) or similar programs in these
states have driven much of the RING development across the country, the current adopted versions
were derived from an older version of GREET model and may not represent the up-to-date
information.This project applied the simplified calculators of OR-GREET to reflect technical and
policy decisions of RNG, particularly, about avoided methane emission credits. In addition, R&D
GREET 2023 was used to estimate carbon intensities of electricity and fossil natural gas to include
the latest updates in GREET40 and estimate CO2 equivalent emissions by using Global Warming
Potential (GWP) over 100-year horizon under The Intergovernmental Panel on Climate Change's
(IPCC) Fifth Assessment Report(AR5), as shown in Exhibit 73.
Exhibit 73. GWP over 100-year Horizon Under AR5
Greenhouse Gases
CO2 1
CH4 30
N20 265
Electricity
EIA's AEO was used to forecast electricity generation mixes for the Pacific region or Northwest Power
Pool Area covered by Western Electricity Coordinating Council (WECC) and U.S.average from 2023
to 2050. EIA and DOE's power generation mixes in Washington and Oregon were used to estimate
the electricity generation mixes in 2022.The electricity generation mix and shares of technologies
for other power plants in the Pacific region are shown in Exhibit 74 and Exhibit 75, respectively.These
mixes were used as inputs of R&D GREET 2023 to estimate electricity carbon intensities in this
region, as summarized in Exhibit 76 with a breakdown of feedstock and combustion at power plants.
Exhibit 74. Electricity Generation Mix in the Pacific Region from 2022 to 2050
Nuclear power
2022 0% 19% 2% 6% 1% 73%
2025 0% 18% 1% 4% 0% 76%
2030 0% 15% 0% 4% 0% 81%
2035 0% 14% 0% 4% 0% 81%
2040 0% 12% 0% 4% 1% 83%
39 https://greet.and.aov/greet_excel_model.models
40 https://greet.anl.gov/publication-greet-2023-summary
CONFIDENTIAL 74 2025 Natural Gas IRP Appendix 310

2045 0% 13% 0% 4% 1% 82%
2050 0% 14% 0% 3% 1% 82%
Exhibit 75. Shares of Technologies for Other Power Plants in the Pacific Region from 2022 to 2050
Hydroelectric • -
2022 85% 0% 13% 1% 1%
2025 81% 0% 17% 2% 0%
2030 68% 0% 30% 2% 0%
2035 68% 0% 30% 2% 0%
2040 61% 1% 32% 7% 0%
2045 60% 1% 32% 7% 0%
2050 59% 1% 32% 8% 0%
Exhibit 76. Electricity Carbon Intensities (gCO2e/kWh)in the Pacific Region from 2022 to 2050
- - . Combustion
Unit gCO2e/kWh
2022 17.7 106.6 124.4
2025 16.3 96.2 112.4
2030 13.0 69.0 82.0
2035 12.5 66.5 79.1
2040 10.9 57.8 68.7
2045 11.8 62.4 74.2
2050 12.1 64.5 76.6
Fossil Natural Gas
Defaults values within R&D GREET 2023 were used to estimate carbon intensities from the upstream
emissions for fossil NG produced in North America, as well as from transmission and distribution
from their production to end use facilities (e.g. boilers).A list of key default settings in R&D GREET
2023 is summarized below and in Exhibit 77,with details to be found in the model:
Methane venting and leakage:Methane transmission and storage: a venting and leakage emission
factor of 64.1 grams of methane per million British thermal units ("gCH4/MMBtu") of NG transported
over 680 miles,alternatively 0.094 gCH4/MMBtu-mile,was assumed to match default values, based
on the hybrid top-down and bottom-up approach. This rate is usually updated based on the most
recent EPA Green House Gas Inventory("GHGI") CH4 emissions data. Methane Distribution: 18.8 g
CH4/MMBtu NG was used in the model.
Fossil NG production: Fossil NG supply was assumed to be composed of 25% conventional gas and
75%shale gas,with a total of 105.1 and 106.1 gCH4/MMBtu NG leakage and venting during recovery,
respectively.
CONFIDENTIAL 75 2025 Natural Gas IRP Appendix 311

Pipeline transmission distance:the distance from NG fields to central end use facilities was
assumed to be 680 miles.
Exhibit 77. CH4 Leakage Rate for Each Stage in Conventional NG and Shale Gas Pathways
Conventional
NG
Recovery - CH4 Leakage and Venting g CH4/MMBtu NG 105.1 106.1
Recovery- Completion CH4 Venting g CH4/MMBtu NG 0.6 1.5
Recovery- Workover CH4 Venting g CH4/MMBtu NG 0.0 0.1
Recovery- Liquid Unloading CH4 Venting g CH4/MMBtu NG 4.3 4.3
Well Equipment - CH4 Venting and Leakage g CH4/MMBtu NG 68.7 68.7
Gathering and Boosting - CH4 Venting and
g CH4/MMBtu NG 31.4 31.4
Leakage
Processing - CH4 Venting and Leakage g CH4/MMBtu NG 6.2 6.2
Transmission and Storage - CH4 Venting and g CH4/MMBtu NG/680
64.1 64.1
Leakage miles
Distribution - CH4 Venting and Leakage g CH4/MMBtu NG 18.8 18.8
As shown in Exhibit 78,the fossil NG carbon intensities would have a minor decrease over years,due
to cleaner U.S. average grid.Approximately 82% of the total is from combustion of NG in boilers.
Exhibit 78. Fossil Natural Gas Carbon Intensities (gCO2e1MMBtu, LHV) from 2022 to 2050
RecoveryNatural Gas Methane Leakage Methane
0 •very& Leakage Combustion •
Processing Processing
Unit gCO2e/MMBtu
2022 5,358 3,372 2,760 1,923 59,587 73,001
2025 5,344 3,372 2,751 1,923 59,587 72,977
2030 5,304 3,372 2,724 1,923 59,587 72,909
2035 5,297 3,372 2,719 1,923 59,587 72,898
2040 5,295 3,372 2,718 1,923 59,587 72,895
2045 5,292 3,372 2,716 1,923 59,587 72,891
2050 5,289 3,372 2,714 1,923 59,587 72,885
RNG
Carbon intensities of RING with feedstocks from landfill gas (LFG),water resource recovery facilities
(WRRF), animal waste, and food waste were estimated in this project.To align with OR CFP,the
modeling concepts of avoided emission credits and methane loss from the simplified calculators of
OR-GREET were applied,yet with the majority of emission factors derived from R&D GREET 2023,
CONFIDENTIAL 76 2025 Natural Gas IRP Appendix 312

particularly considering about the carbon intensities of grid electricity and fossil natural gas from the
above analysis. A list of assumptions was made, as shown in Exhibit 79. In addition,the avoided
emissions credits for animal manure and food waste were estimated as:
Animal waste:1,000 dairy cows with 21.8 MMBtu CH4 per year per cow of biogas production at
Portland, OR.The methane production was based on tables A.1 and A.2 under the Reference tab of
the simplified calculator. No lagoon cleanout was considered as the manure management practice,
and covered lagoon was assumed as the digester type.This resulted in -9.9 grams of avoided
methane per MJ RNG, and -22.2 grams of diverted CO2 emissions per MJ RNG.
Food waste:1 ton of wet food waste,with 60 kg CH4 per ton of wet food waste of biogas production,
based on the FS Fate tab of the simplified calculator.This resulted in -136,044 gCO2e/MMBtu RNG of
avoided emission credits and 13,291 gCO2e/MMBtu RNG credit adjustments.
The estimated RNG carbon intensities by feedstock are summarized in Exhibit 80.
Exhibit 79. Assumptions to estimate RNG carbon intensities
®® Animal
Manure
. . .
Electricity Use kWh/MMBtu RNG 30 35 35 40
MMBtu
NG Use NG/MMBtu RNG 6% 5% 35% 35%
T&D Distance
(Pipeline) Miles 50 50 50 50
Methane Loss % 1% 1% 2% 2%
Exhibit 80. RNG carbon intensities (gCO2e1MMBtu, LHV) from 2022 to 2050
Animal Manure
. . .
Unit gCO2e/MMBtu
2022 14,963 14,855 -235,036 -79,045
2025 14,603 14,436 -235,462 -79,532
2030 13,686 13,367 -236,551 -80,773
2035 13,599 13,265 -236,656 -80,893
2040 13,287 12,902 -237,020 -81,309
2045 13,450 13,092 -236,831 -81,092
2050 13,523 13,177 -236,748 -80,997
Stochastic Modeling for Simulated Values
The Monte Carlo simulation is a mathematical technique that generates a set of possible outcomes
or"cases" of one or many uncertain event(s).The values of the Monte Carlo variables are then used
to make (for each case)the main calculations needed in the analysis. For the low-carbon options
evaluated here,the Monte Carlo variables are typically components of capital and operating costs or
resource constraints and the main calculations are the per-unit cost of the resource and the amount
of the resource that is expected to be available in each forecast year.The inputs of the Monte Carlo
CONFIDENTIAL 77 2025 Natural Gas IRP Appendix 313

process are statistical descriptions of the distribution of each stochastic variable(e.g.,factor prices
and physical limits) and the outputs are the case results which depict the distribution of the main
calculations (e.g. resource costs and quantities).
ICF used an Excel-based stochastic pathways simulation tool to create a range of possible values for
input parameters that determine both levelized costs and technical potential for each year from
2025 to 2050 for each resource.This model contained ICF's recommended statistical distribution
(e.g.,type of distribution, max, min, mean,standard deviation, etc.)for each input parameter and will
generated 1,000 or more cases. Any correlations among input parameters as specified by the user
were taken into account as samples were drawn from their respective distributions during the
process by which the 1,000+ cases were generated.
For each variable and forecast year, ICF defined the type of statistical distribution (triangular, normal
distribution,and uniform), and defined the mean/mode and shape of the distribution. Below are the
description of the variables.
Global Variables (variables that are used across technology types)
• Brent crude oil price (Triangular distribution, Min = 0.870 of mode; Max= 1.900 of mode): Base
Case is set to be AEO reference case forecast for each year. Min and Max are defined by the
range of outcomes seen in AEO alternative cases (using the year 2050 data).
• Natural gas Henry Hub price (Triangular distribution, Min = 0.730 of mode; Max = 1.690 of mode):
Base Case is set to be AEO reference case forecast. Min and Max are defined by the range of
outcomes seen in AEO alternative cases (using the year 2050 data).
• NW regional and national electricity generation price(Triangular distribution, Min = 0.900 of
mode; Max = 1.180 of mode): Base Case is set to be AEO reference case forecast. Min and Max is
defined by AEO alternative cases (using the year 2050 data).
• NW regional and national electricity transportation and distribution price(Triangular distribution,
Min = 0.900 of mode; Max = 1.070 of mode): Base Case is set to be AEO reference case forecast.
Min and Max is defined by AEO alternative cases (using the year 2050 data).
• Construction cost index(Normal distribution, Min = 0.800 of mean; Max = 1.200 of mean): Base
Case's annual growth rate is derived from historical data from the U.S. Bureau of Labor Statistics,
new industrial building construction cost index. Min and Max are set to be +/- 20% of the mean
by 2050, based on observed historical data standard deviation and ICF's estimation.
• Construction machinery cost index(Normal distribution, Min = 0.900 of mean; Max =1.100 of
mean): Base Case's annual growth rate is derived from historical data from the U.S. Bureau of
Labor Statistics,construction machinery cost index. Min and Max are set to be +/- 10% of the
mean by 2050, based on observed historical data standard deviation and ICF's estimation.
• Water commodity cost(Normal distribution, Min = 0.900 of mean; Max= 1.100 of mean): Base
Case's annual growth rate is derived from the U.S. Department of Energy,office of Scientific and
Technical Information's forecast on water and wastewater annual price escalation rates (2023
edition). Based on ICF's estimation, Min and Max are set to be +/- 10% of the mean.
• Weighted average cost of capital (Normal distribution, Min = 0.750 of mean; Max = 1.250 of mean):
based on Utilities'data,the Base Case weighted average cost of capital in real terms is set to be
4%. Based on ICF estimation,the Min is set to be 3% and the max is set to be 5%.
• Technical Potential Index(Normal distribution, Min = 0.800 of mean; Max = 1.200 of mean): The
Base Case reflects ICF's forecast on technical potential for each technology in terms or the
CONFIDENTIAL 78 2025 Natural Gas IRP Appendix 314

maximum amounts of each resource type and category that could be available in each forecast
year.To reflect the high uncertainty associated with technical potential, ICF conducted a
stochastic modeling on the base case with the Min and Max set to be +/- 20% of the base case
by 2050.
Technology-Specific Assumptions:
• Well D&C cost index(Normal distribution, Min = 0.900 of mean; Max =1.100 of mean): Base Case's
annual growth rate is derived from historical data from the U.S. Bureau of Labor Statistics, drilling
costs for oil and gas cost index(which is applied also to CO2 and H2 wells). Min and Max are set to
be +/-10% of the mean by 2050, based on observed historical data standard deviation and ICF's
estimation.
• Wind power levelized cost of electricity(LCOE) cost index(Normal distribution, Min = 0.900 of
the mean; Max = 1.100 of mean): Base Case LCOE is developed using AEO's projections for wind
power Capex,OPEX,and capacity factor. Based on ICF's estimation, Min and Max are set to be +/-
10%of the mean by 2050.
• Solar power LCOE cost index(Normal distribution, Min = 0.900 of the mean; Max = 1.100 of mean):
Base Case LCOE is developed using AEO's projections for solar power Capex, OPEX, and capacity
factors. Based on ICF's estimation, Min and Max are set to be +/- 10%of the mean by 2050.
• Nuclear power LCOE cost index(Normal distribution, Min = 0.900 of the mean; Max =1.100 of
mean): Base Case LCOE is developed using AEO's projections for nuclear power Capex,OPEX,and
capacity factor. Based on ICF's estimation, Min and Max are set to be +/- 10% of the mean by
2050.
• REC price premium cost index (Triangular distribution, Mode = 5%, Min = 0% ; Max = 30%).The
Base Case assumes a 5% REC price premium, indicating that REC prices are 5% higher than
renewable electricity prices. Significant uncertainties surround REC prices due to the early stage
of market development and the Hydrogen tax credit's hourly matching requirement.These
uncertainties may make it difficult for utilities to procure enough RECs to keep the electrolyzer
running near full capacity.The broad range of REC price premiums reflects these uncertainties
and the risk of higher REC prices due to market supply-demand constraints.
• Electrolyzer learning rate (Triangular distribution, Min = 0.454 of mode; Max = 1.150 of mode): The
Base Case learning rate is established at 22% according to ICF's projection. This means that
capital costs decline for each doubling of worldwide installed capacity. The minimum and
maximum rates are set at 5% and 25%, respectively.This broad distribution range, particularly
below the mode, highlights the significant uncertainty linked to this assumption.
• Methane pyrolysis Learning rate(Triangular distribution, Min = 0.600 of mode; Max = 2.000 of
mode):The Base Case learning rate is established at 5% according to ICF's projection.The
minimum and maximum rates are set at 3%and 10%, respectively.This broad distribution range,
particularly above the mode, highlights the significant uncertainty linked to this assumption.
• Hydrogen thermal efficiency(applicable for green, pink, and turquoise hydrogen,Triangular
distribution, Min = 1 of mode; Max = 1.300 of mode): The Base Case assumes no annual
improvement,which is also the minimum value.The maximum improvement is set at 0.3% per
year.These assumptions account for potential technological advancements that could enhance
CONFIDENTIAL 79 2025 Natural Gas IRP Appendix 315

the thermal efficiency of electrolyzers and pyrolysis. Since Blue Hydrogen (ATR)technology is
relatively mature, its thermal efficiency improvement is set at 0 in all Monte Carlo cases.
• RNG/Syngas Capex(Normal distribution, Min = 0.900 of mean; Max= 1.100 of mean):The Base
Case is set to decline by 5% by 2050 in real dollars, before adjustment of Construction cost
index,which reflects expected technological advancement. Based on ICF's estimation, Min and
Max are set to be +/- 10% of the mean by 2050.
• RNG/Syngas Equipment cost index(Triangular distribution, Min = 0.950 of mode; Max= 1.250 of
mode):the Base Case is set to stay at the same level in real dollars, before adjustment of
Construction machinery cost index. Based on ICF's estimation,the Min is set to be 5% below the
mode and the Max is set to be 25% above the mode.
• Carbon Black Price (Triangular distribution, Min = 0.000 of mode; Max = 50.000 of mode):The
Base Case carbon black price is set to 1 cent per Kg of carbon black(a number close to 0) as the
Base Case is set to not include byproduct revenues.The Min is set to be 0 and the Max is set to
be$ 0.50 per Kg of carbon black,which reflects the possible market price of carbon black
according to studies such as Hydrogen Europe's Clean Hydrogen Production Pathways (2024
report).
The table below shows the applicable stochastic variables to each fuel type.
Exhibit 81.Applicable Stochastic Variables to Each Fuel Type
Blue H2 Green&Pink Turquoise
(Electrolyzer) Pyrolysis)
Brent crude oil Yes?
Natural gas Henry Hub Yes Yes Yes?
Electricity generation Yes Yes Yes Yes Yes Yes
Electricity T&D Yes Yes Yes Yes Yes Yes
Construction cost Yes Yes Yes Yes Yes Yes
index
Construction Yes Yes Yes Yes Yes Yes
machinery cost index
Water commodity Yes Yes Yes Yes Yes Yes
cost
Weighted average Yes Yes Yes Yes Yes Yes
cost of capital
Technical Potential Yes Yes Yes Yes Yes Yes
Index
Well D&C cost index Yes?
CONFIDENTIAL 80 2025 Natural Gas IRP Appendix 316

Wind power LCOE Yes
cost index
Solar power LCOE Yes
cost index
Nuclear power LCOE Yes
cost index
Electrolyzer learning Yes
rate
Methane pyrolysis Yes
Learning rate
Hydrogen thermal Yes Yes
efficiency
RNG/Syngas Capex Yes Yes
RNG/Syngas Yes Yes
Equipment cost index
Carbon Black Price Yes
For the global variables, ICF performed regression tests on historical data and selected valid
correlation coefficients for pairs with strong regression fits (t-stat > 2.064, 95% confidence level for
24 degrees of freedom). ICF also made assumptions about the correlation coefficients between
global variables and technology-specific variables. For instance, since the construction of wind and
solar power primarily involves construction and machinery costs, ICF assigned correlation
coefficients of 0.4 and 0.2 with the construction cost index and construction machinery cost index,
respectively.The graph below shows the correlation assumptions for each pair of variables.
CONFIDENTIAL 81 2025 Natural Gas IRP Appendix 317

Exhibit 82. Correlation Assumptions for Each Pair of Variables.
Weed Learning LearningGreen,
Construc Water Rate Pink and
Electricity Electricity Avr Cost Well Rate RNG/Sy
Brent
Nat Gas Generati Trans& of Capital D&C Construc lion Commo Technics Wind Solar NuclearIndex- ngas Index- Turquois RNG/Sy Carbon
HH ton Cost Machine dity- I LCOE LCOE Electroly a ngas Black(in
Correlation Coefficient Inputs Crude Oil on- Dist- Index Cost LCOE Pyrolysis Equipme
($/MMBt Index ryCost Annual Potential 1=Base 1=Base zer Hydroge Capex $2022,
($/bbl) u) Regional Regional 1=2022 Index Escalato (Base Index Index Case Case 1-2022 (Base (Base n 1=2022 1nt Index=2022 cent)
$/MWH $/MWH 1=2022 n Case 1=2022 Case= Case Thermal 1=2022
=1) 1 1) Efficient
Brent Crude Oil $/bbl
Nat Gas HH $/MMBtu 0.10
Electricity Generation-Regional$/MWH 0.20
Electricity Trans&Dist-Regional$/MWH
Construction Cost Index 1=2022 0.10 0.20
Construction Machinery Cost Index 1=2022 0.20 0.20 0.80 ELLIJIM
Water Commodity-Annual Escalation
Wt'ed Avr Cost of Capital Index Base Case=1 0.10 0.10 0.40
Technical Potential Index
Well D&C Cost Index 1=2022 0.80
Wind LCOE 1=13ase Case 0.40 0.20 0.10
Solar LCOE 1=13ase Case 0.40 0.20 0.10 i
Nuclear LCOE 1=2022 0.40 0.20 0.10 =I Um
Learning Rate Index-Electrol er Base Case=1
Learning Rate Index-Pyrolysis Base Case=1
Green,Pink and Turquoise Hydrogen Thermal Efficiency
RNG/S n as Ca ex 1=2022
RNG/S n as Equipment Index 1=2022 0.50 0.50
Carbon Black in$2022,cent
CONFIDENTIAL 82 2025 Natural Gas IRP Appendix 318

Using the predefined distribution curves and correlations,the model generated 1,000 random cases.
These cases were applied to each technoeconomic model. In each case and year,all variables used
the same set of random number multipliers to maintain consistency across global variables and
minimize discrepancies between predefined and modeled correlations.All technoeconomic models
used the same set of 1,000 draws to ensure uniformity in global variables across different fuel types.
CONFIDENTIAL 83 2025 Natural Gas IRP Appendix 319

Appendix
ICF's Approach to LCOE Calculation
The LCOE, a measure of the average net present cost of fuel production at a facility over its
anticipated lifetime, enables comparison across low-carbon fuels and other energy types on a
consistent per-unit energy basis. ICF employs a consistent method for modeling LCOE across
different fuels: it is calculated as the discounted costs over the lifetime of energy production (e.g.,
RING production) divided by a discounted sum of the actual energy amounts produced.41 All capital
and operating expenses are specified by year of occurrence and using specific financial
assumptions are discounted back to year zero. Likewise,the volume of sales of the product or
service(measured in, say, MMBtu or metric tons) is also specified by year and discounted back to
year zero.The formula below shows the LCOE calculation.
yn It +Mt +Ft
t=1 (1 +r)t
LCOE _
yr 1(1 +tr)t
where It is the capital cost expenditures (or investment expenditures) in year t,Mt represents the
operations and maintenance expenses in year t,Ft represents the feedstock costs in year t(where
appropriate),Et represents the energy produced in year t,r is the discount rate,and n is the
expected lifetime of the production facility.
ICF usually first computes the levelized costs before any effects of federal tax credits such as those
provided under the Inflation Reduction Act(IRA).Then a second levelized cost is computed including
the effects of tax credits.This involves figuring out which credits apply and how large they will be
given various emission criteria, labor requirements,domestic content limits,and other provisions.
Since the tax credits are available only for projects beginning construction before certain dates and
any qualified project can enjoy the credits only for a limited number of years,the credit value will
change over time and might be different for different vintages (that is, start dates) of the project.
The method used by ICF in dealing with these complexities is to compute the value of the credits
(levelized over the project life) individually for projects that come online each year.
If there are coproducts (e.g., the sale of captured CO2 for enhanced oil recovery),the revenues from
coproducts need to be calculated by year and those revenues credited against annual expenditures
before calculating the NPV of costs.This can be done by using a projected coproduct price.An
alternative methodology that ICF has used for synthetic fuel technologies that produce multiple
hydrocarbon products, is to add all products together and compute the average levelized cost in
$/MMBtu for all outputs.
41 It is then adjusted for any severance taxes, royalties or fees that the provider might owe per unit of
production.
CONFIDENTIAL 84 2025 Natural Gas IRP Appendix 320

**ICF
© https://twitter.com/ICF
® linkedin.com/company/icf-international
facebook.com/ThislslCF
id.com #thisisicf
About ICF
ICF(NASDAQ:ICFI) is a global consulting services company with approximately 9,000 full-time and
part-time employees, but we are not your typical consultants.At ICF, business analysts and policy
specialists work together with digital strategists,data scientists and creatives.We combine
unmatched industry expertise with cutting-edge engagement capabilities to help organizations solve
their most complex challenges. Since 1969, public and private sector clients have worked with ICF to
navigate change and shape the future.
CONFIDENTIAL 85 2025 Natural Gas IRP Appendix 321

Weighted Average Cost of Capital
Discount Factor
Idaho 6.67%
Oregon 6.71%
Washington 6.51%
2025 Natural Gas IRP Appendix 322

ALTERNATIVE FUELS AVAILABLE SUPPLY (THOUSANDS OF
DEKATHERMS)
Expected
HydrogenYear Blue Green 1-12- Greenl-12- Microwave
2030 2,667 3,734 3,734 10
2031 3,544 4,957 4,957 14
2032 4,421 6,181 6,181 18
2033 5,299 7,404 7,404 23
2034 6,176 8,628 8,628 27
2035 7,053 91851 9,851 31
2036 7,313 9,672 9,672 194
2037 7,572 9,493 9,493 356
2038 7,832 9,314 9,314 519
2039 8,091 9,136 9,136 681
2040 8,350 10,745 10,745 844
2041 8,447 10,777 10,777 844
2042 8,544 10,810 10,810 845
2043 8,641 10,842 10,842 845
2044 8,738 10,875 10,875 845
2045 8,835 10,907 10,907 846
Year Animal Animal Landfill Landfill Landfill Landfill Landfill
2030 123 185 197 197 395 493 691
2031 158 237 217 217 434 543 760
2032 193 290 236 236 473 591 827
2033 225 338 255 255 510 637 892
2034 251 377 272 272 545 681 953
2035 272 407 289 289 577 722 1,010
2036 286 429 303 303 607 758 1,062
2037 296 445 317 317 633 792 1,108
2038 303 455 329 329 657 821 1,149
2039 308 462 339 339 677 847 1,186
2040 311 467 348 348 695 869 1,217
2041 313 469 356 356 711 888 1,244
2042 314 471 362 362 724 905 1,267
2043 315 473 368 368 735 919 1,286
2044 315 473 372 372 744 930 1,302
2045 316 474 376 376 752 940 1,316
2025 Natural Gas IRP Appendix 323

Year Wastewater Wastewater Wastewater Wastewater Wastewater
2030 7 7 7 36 14
2031 9 9 9 44 18
2032 10 10 10 52 20
2033 12 12 12 59 23
2034 13 13 13 65 26
2035 14 14 14 71 28
2036 15 15 15 75 30
2037 16 16 16 78 31
2038 16 16 16 81 32
2039 16 16 16 83 33
2040 17 17 17 84 34
2041 17 17 17 85 34
2042 17 17 17 86 34
2043 17 17 17 86 35
2044 17 17 17 87 35
2045 18 18 18 87 35
I FFINfa 0 0 0 TV . -: oil = Greenl-12-
2030 42 58 77 58 184
2031 54 103 137 103 253
2032 67 180 240 180 319
2033 77 307 409 307 386
2034 87 501 668 501 401
2035 93 767 1,022 767 400
2036 99 1,082 1,442 1,082 459
2037 102 1,396 1,862 1,396 640
2038 104 1,662 2,216 1,662 762
2039 106 1,856 2,475 1,856 962
2040 107 1,983 2,644 1,983 1,295
2041 108 2,060 2,747 2,060 1,397
2042 108 2,105 2,807 2,105 1,406
2043 108 2,131 2,841 2,131 1,406
2044 109 2,145 2,860 2,145 1,406
2045 109 2,153 2,871 2,153 1,407
Low
Year Blue Green 1-12- Greenl-12- Microwave
. . . -
2030 2,264 3,170 3,170 8
2031 2,831 3,960 3,960 11
2025 Natural Gas IRP Appendix 324

2032 3,398 4,751 4,751 14
2033 3,965 5,541 5,541 17
2034 4,532 6,331 6,331 20
2035 5,099 7,121 7,121 23
2036 5,076 7,263 7,263 119
2037 5,053 71404 7,404 215
2038 5,029 7,546 7,546 311
2039 5,006 7,688 7,688 407
2040 4,983 6,411 6,411 504
2041 4,817 6,155 6,155 483
2042 4,652 5,899 5,899 461
2043 4,486 5,643 5,643 440
2044 4,321 5,386 5,386 419
2045 4,155 5,130 5,130 398
aAnimal Animal Landfill Landfill Landfill Landfill Landfill
2030 105 157 168 168 335 419 587
2031 127 191 177 177 354 442 619
2032 150 224 186 186 372 465 651
2033 169 254 194 194 389 486 680
2034 185 277 202 202 404 505 707
2035 196 295 209 209 417 522 730
2036 199 298 210 210 421 526 736
2037 198 297 211 211 422 528 739
2038 195 293 211 211 422 527 738
2039 191 286 210 210 419 524 733
2040 186 279 208 208 415 519 726
2041 179 268 203 203 405 506 709
2042 172 257 197 197 393 492 689
2043 164 246 191 191 381 476 667
2044 156 234 184 184 368 460 643
2045 149 223 177 177 354 442 619
Year Wastewater Wastewater Wastewater Wastewater Wastewater
2030 6 6 6 31 12
2031 7 7 7 35 14
2032 8 8 8 40 16
2033 9 9 9 45 18
2034 9 9 9 48 19
2035 10 10 10 51 20
2036 10 10 10 52 21
2025 Natural Gas IRP Appendix 325

2037 11 11 11 52 21
2038 10 10 10 52 21
2039 10 10 10 51 20
2040 10 10 10 50 20
2041 10 10 10 49 19
2042 9 9 9 47 19
2043 9 9 9 45 18
2044 8 8 8 43 17
2045 8 8 8 41 16
mo
. . . Waste Biomass Biomass Biomass GreenH2-
•
2030 36 49 65 49 157
2031 44 77 103 77 204
2032 52 132 176 132 247
2033 58 224 298 224 291
2034 64 363 484 363 295
2035 68 554 739 554 289
2036 68 728 971 728 306
2037 68 898 1,197 898 408
2038 67 1,035 1,380 1,035 472
2039 66 1,128 1,504 1,128 583
2040 64 1,183 1,578 1,183 773
2041 62 1,174 1,565 1,174 796
2042 59 1,145 1,526 1,145 764
2043 57 1,105 1,473 1,105 729
2044 54 1,060 1,413 1,060 694
2045 51 1,013 1,350 1,013 662
2025 Natural Gas IRP Appendix 326

COMPLIANCE MECHANISMS COST PER MTCO2e (Nominal $)
Expected
Year Allowance CCI Animal Manure 4 Animal Manure 5 . . . Waste
2026 $44 $141 $1,428 $1,225 $1,496
2027 $49 $144 $1,459 $1,251 $1,529
2028 $55 $148 $1,493 $1,280 $1,565
2029 $62 $152 $1,531 $1,312 $1,605
2030 $70 $157 $1,571 $1,346 $1,646
2031 $79 $162 $1,613 $1,382 $1,689
2032 $89 $167 $1,657 $1,420 $1,734
2033 $91 $172 $1,703 $1,460 $1,781
2034 $93 $177 $1,749 $1,499 $1,828
2035 $95 $182 $1,794 $1,537 $1,874
2036 $97 $187 $1,839 $1,575 $1,920
2037 $99 $193 $1,885 $1,614 $1,968
2038 $101 $198 $1,933 $1,656 $2,017
2039 $103 $204 $1,981 $1,696 $2,067
2040 $106 $210 $2,032 $1,740 $2,119
2041 $108 $216 $2,084 $1,785 $2,173
2042 $110 $222 $2,136 $1,829 $2,227
2043 $113 $228 $2,189 $1,874 $2,281
2044 $115 $234 $2,244 $1,920 $2,338
2045 $117 $241 $2,301 $1,968 $2,397
Year Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas
6MM (RTC) (RTC) I I (RTC)I (RTC) (RTC)MI
2026 $1,003 $494 $347 $275 $230
2027 $1,029 $505 $354 $280 $233
2028 $1,057 $517 $362 $286 $238
2029 $1,088 $531 $371 $293 $244
2030 $1,121 $545 $381 $301 $250
2031 $1,155 $561 $392 $309 $257
2032 $1,191 $577 $403 $318 $264
2033 $1,228 $595 $416 $328 $272
2034 $1,266 $613 $428 $337 $280
2035 $1,303 $629 $439 $346 $287
2036 $1,342 $647 $451 $355 $295
2037 $1,381 $664 $463 $364 $303
2038 $1,422 $683 $476 $375 $311
2039 $1,464 $702 $489 $385 $319
2025 Natural Gas IRP Appendix 327

2040 $1,508 $722 $502 $395 $328
2041 $1,553 $742 $516 $406 $337
2042 $1,599 $762 $530 $416 $345
2043 $1,646 $783 $543 $427 $354
2044 $1,695 $804 $558 $438 $363
2045 $1,745 $826 $572 $449 $371
Year Wastewater Wastewater Wastewater Wastewater Wastewatejr-
2026 $1,388 $1,229 $502 $355 $269
2027 $1,426 $1,260 $511 $360 $271
2028 $1,468 $1,297 $523 $367 $276
2029 $1,514 $1,337 $537 $376 $282
2030 $1,563 $1,380 $553 $387 $290
2031 $1,616 $1,425 $571 $399 $299
2032 $1,670 $1,473 $589 $412 $309
2033 $1,729 $1,524 $610 $428 $321
2034 $1,787 $1,575 $630 $442 $332
2035 $1,844 $1,625 $648 $455 $342
2036 $1,902 $1,675 $666 $467 $351
2037 $1,963 $1,728 $686 $480 $360
2038 $2,027 $1,783 $707 $495 $372
2039 $2,089 $1,838 $726 $507 $381
2040 $2,158 $1,897 $748 $523 $393
2041 $2,227 $1,958 $771 $539 $404
2042 $2,298 $2,018 $792 $552 $414
2043 $2,370 $2,080 $812 $566 $423
2044 $2,444 $2,145 $834 $580 $433
2045 $2,522 $2,212 $857 $595 $443
Under i i 00 00
25MMBtu/hr- Industrial Industrial P1 Industrial Industrial
00
2026 N/A N/A N/A N/A
2027 N/A N/A N/A N/A
2028 N/A N/A N/A N/A
2029 N/A N/A N/A N/A
2030 $523 $286 $274 $171
2031 $537 $294 $282 $177
2032 $551 $303 $290 $182
2033 $565 $311 $298 $188
2034 $579 $320 $306 $193
2025 Natural Gas IRP Appendix 328

2035 $593 $328 $315 $199
2036 $624 $353 $339 $221
2037 $655 $378 $364 $243
2038 $687 $404 $391 $267
2039 $720 $431 $418 $291
2040 $754 $460 $446 $316
2041 $772 $470 $456 $324
2042 $789 $481 $467 $332
2043 $807 $493 $478 $340
2044 $825 $504 $490 $348
2045 $844 $516 $502 $356
Year 200-400MMBtu/hr- 800-1600MMBtu/hr- Direct Air Capture-
DA
2026 N/A N/A N/A
2027 N/A N/A N/A
2028 N/A N/A N/A
2029 N/A N/A N/A
2030 $126 $72 $709
2031 $131 $75 $715
2032 $135 $79 $721
2033 $139 $82 $727
2034 $144 $85 $733
2035 $148 $89 $738
2036 $169 $108 $759
2037 $190 $128 $780
2038 $212 $149 $802
2039 $235 $171 $824
2040 $259 $194 $847
2041 $265 $199 $855
2042 $272 $204 $863
2043 $278 $209 $871
2044 $285 $215 $879
2045 $292 $220 $887
High
Year Allowance Animal Manure 4 Animal Ma . . .
(RTC) /rM%r:jM IOT
2026 $56 $1,606 $1,375 $1,688
2027 $64 $1,641 $1,405 $1,724
2028 $72 $1,680 $1,438 $1,765
2029 $81 $1,722 $1,474 $1,809
F2-0-3—OT $93 $1,768 $1,513 $1,855
2025 Natural Gas IRP Appendix 329

2031 $101 $1,815 $1,553 $1,904
2032 $116 $1,865 $1,596 $1,954
2033 $118 $1,917 $1,641 $2,007
2034 $119 $1,969 $1,685 $2,060
2035 $125 $2,019 $1,728 $2,111
2036 $127 $2,069 $1,771 $2,163
2037 $134 $2,121 $1,815 $2,217
2038 $137 $2,176 $1,862 $2,272
2039 $141 $2,229 $1,907 $2,328
2040 $144 $2,287 $1,956 $2,387
2041 $148 $2,346 $2,006 $2,447
2042 $149 $2,404 $2,056 $2,508
2043 $155 $2,464 $2,106 $2,570
2044 $162 $2,526 $2,159 $2,634
2045 $166 $2,589 $2,212 $2,700
Year Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas
MokRTC) (RTC) (RTC) (RTC) (RTC)
2026 $1,134 $560 $397 $316 $259
2027 $1,163 $573 $405 $321 $263
2028 $1,195 $587 $415 $327 $269
2029 $1,230 $602 $425 $335 $275
2030 $1,266 $619 $437 $344 $283
2031 $1,305 $637 $449 $353 $291
2032 $1,345 $655 $461 $363 $299
2033 $1,388 $675 $475 $374 $309
2034 $1,430 $695 $489 $385 $318
2035 $1,472 $714 $501 $395 $327
2036 $1,515 $734 $515 $405 $335
2037 $1,560 $754 $529 $416 $344
2038 $1,607 $775 $544 $428 $354
2039 $1,654 $797 $559 $439 $364
2040 $1,703 $819 $574 $451 $374
2041 $1,754 $842 $590 $463 $384
2042 $1,806 $865 $605 $475 $393
2043 $1,860 $888 $621 $487 $403
2044 $1,915 $913 $637 $499 $412
2045 $1,972 $937 $654 $512 $422
Year Wastewater Wastewater Wastewater Wastewater Wastewater
2025 Natural Gas IRP Appendix 330

2026 $1,575 $1,393 $584 $407 $306
2027 $1,617 $1,429 $594 $412 $308
2028 $1,664 $1,471 $608 $419 $313
2029 $1,716 $1,516 $625 $430 $321
2030 $1,772 $1,565 $643 $442 $330
2031 $1,831 $1,617 $664 $455 $340
2032 $1,893 $1,671 $685 $470 $351
2033 $1,960 $1,729 $709 $487 $365
2034 $2,026 $1,787 $732 $503 $377
2035 $2,091 $1,843 $754 $517 $388
2036 $2,156 $1,900 $775 $531 $398
2037 $2,225 $1,960 $797 $546 $410
2038 $2,297 $2,023 $822 $563 $423
2039 $2,368 $2,084 $843 $577 $433
2040 $2,445 $2,151 $869 $595 $447
2041 $2,525 $2,220 $895 $613 $460
2042 $2,604 $2,289 $920 $628 $471
2043 $2,686 $2,359 $944 $644 $481
2044 $2,770 $2,432 $969 $660 $492
2045 $2,859 $2,508 $996 $676 $504
Low
Year Animal Manure 4 Animal Manure 5 . . . Waste 3
2026 $1,242 $1,066 $1,301
2027 $1,269 $1,089 $1,329
2028 $1,299 $1,114 $1,361
2029 $1,332 $1,142 $1,395
2030 $1,367 $1,172 $1,430
2031 $1,404 $1,203 $1,468
2032 $1,441 $1,235 $1,507
2033 $1,482 $1,270 $1,548
2034 $1,521 $1,304 $1,589
2035 $1,560 $1,337 $1,629
2036 $1,599 $1,370 $1,669
2037 $1,639 $1,405 $1,710
2038 $1,682 $1,441 $1,752
2039 $1,723 $1,476 $1,795
2040 $1,768 $1,515 $1,840
2041 $1,813 $1,553 $1,887
2042 $1,858 $1,592 $1,934
2043 $1,904 $1,630 $1,982
2044 $1,952 $1,671 $2,031
2025 Natural Gas IRP Appendix 331

2045 1 $2,001 $1,712 $2,082
Year Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas
2026 $866 $423 $297 $236 $194
2027 $888 $433 $303 $240 $198
2028 $913 $443 $309 $246 $203
2029 $939 $455 $317 $252 $208
2030 $967 $468 $326 $258 $213
2031 $996 $482 $335 $266 $219
2032 $1,027 $496 $345 $273 $226
2033 $1,059 $511 $356 $281 $233
2034 $1,092 $526 $367 $290 $240
2035 $1,124 $541 $376 $297 $246
2036 $1,157 $555 $386 $305 $252
2037 $1,191 $571 $397 $313 $259
2038 $1,226 $587 $408 $322 $266
2039 $1,262 $603 $419 $330 $273
2040 $1,300 $620 $431 $339 $280
2041 $1,339 $638 $443 $348 $288
2042 $1,379 $655 $455 $357 $295
2043 $1,420 $673 $466 $366 $302
2044 $1,462 $692 $479 $375 $309
2045 $1,505 $711 $491 $384 $317
Year Wastewater Wastewater Wastewater Wastewater Wastewater
2026 $1,194 $1,061 $430 $302 $228
2027 $1,227 $1,088 $439 $305 $231
2028 $1,263 $1,120 $449 $311 $235
2029 $1,303 $1,154 $462 $319 $240
2030 $1,346 $1,192 $476 $328 $248
2031 $1,391 $1,231 $491 $339 $255
2032 $1,438 $1,272 $507 $350 $264
2033 $1,488 $1,316 $525 $363 $274
2034 $1,539 $1,360 $542 $375 $284
2035 $1,588 $1,403 $557 $386 $292
2036 $1,638 $1,447 $573 $396 $299
2037 $1,690 $1,492 $590 $407 $307
2038 $1,745 $1,540 $608 $420 $317
2039 $1,799 $1,586 $624 $430 $324
2025 Natural Gas IRP Appendix 332

2040 $1,857 $1,637 $644 $444 $334
2041 $1,918 $1,690 $663 $457 $344
2042 $1,978 $1,742 $680 $469 $352
2043 $2,040 $1,796 $698 $480 $360
2044 $2,105 $1,851 $717 $492 $368
2045 $2,171 $1,909 $736 $504 $377
2025 Natural Gas IRP Appendix 333

LEVELIZED ANNUAL COST OF ELECTRIFICATION
EQUIVALENT TO ONE DEKATHERM PER DAY (NOMINAL $)
2026 $29.62 $37.87 $67.60 $33.43 $38.61 $25.74
2027 $28.79 $39.61 $70.43 $33.31 $40.50 $27.74
2028 $27.77 $41.36 $73.47 $33.18 $42.58 $29.85
2029 $29.27 $43.35 $76.89 $35.07 $44.84 $32.13
2030 $30.94 $45.44 $80.60 $37.21 $47.33 $34.56
2031 $32.73 $47.65 $84.69 $39.53 $50.09 $37.15
2032 $34.70 $49.93 $89.10 $42.12 $53.07 $39.91
2033 $51.19 $92.22 $116.84 $44.70 $56.33 $42.91
2034 $53.95 $96.96 $123.05 $47.42 $59.74 $46.11
2035 $56.80 $102.16 $129.89 $50.33 $63.51 $49.56
2036 $60.03 $107.59 $137.23 $53.59 $67.62 $53.26
2037 $63.41 $113.42 $145.20 $57.06 $72.08 $57.22
2038 $67.24 $119.28 $153.53 $60.95 $76.80 $61.42
2039 $71.30 $125.45 $162.41 $65.13 $81.87 $65.91
2040 $76.51 $131.60 $171.70 $70.18 $87.30 $70.65
2041 $82.16 $138.13 $181.67 $75.68 $93.18 $75.73
2042 $88.21 $144.69 $192.19 $81.55 $99.37 $80.71
2043 $94.14 $151.36 $202.97 $87.32 $105.65 $85.51
2044 $100.40 $158.10 $214.12 $93.30 $112.07 $90.09
2045 $105.46 $165.42 $225.98 $98.59 $118.72 $94.37
•
2026 $60.84 $65.01 $107.58 $178.54 $129.68 $288.56
2027 $62.73 $68.31 $112.48 $182.83 $135.83 $302.65
2028 $64.66 $71.90 $117.90 $186.78 $142.50 $317.48
2029 $66.68 $75.64 $123.77 $190.57 $149.47 $333.06
2030 $69.27 $79.59 $130.17 $196.63 $156.95 $349.41
2031 $72.01 $83.81 $137.21 $202.68 $165.05 $366.64
2032 $75.19 $88.22 $144.80 $210.61 $173.66 $384.72
2033 $116.69 $168.72 $196.68 $217.89 $182.95 $403.86
2034 $120.40 $178.32 $207.92 $223.98 $193.20 $424.26
2035 $125.27 $188.02 $219.82 $232.63 $203.75 $445.44
2036 $130.35 $198.52 $232.79 $241.47 $215.14 $467.83
2037 $135.56 $209.70 $246.80 $250.06 $227.24 $491 .29
2025 Natural Gas IRP Appendix 334

2038 $141.57 $220.98 $261.43 $260.37 $239.46 $515.32
2039 $148.55 $232.03 $276.52 $272.87 $251.98 $540.14
2040 $155.87 $243.57 $292.64 $285.81 $265.22 $565.87
2041 $163.62 $255.47 $309.73 $299.43 $279.12 $592.76
2042 $172.25 $267.03 $327.44 $314.86 $292.96 $619.86
2043 $181.14 $278.92 $345.71 $330.63 $307.29 $647.59
2044 $190.39 $291.57 $365.00 $346.61 $322.26 $675.66
2045 $199.86 $304.52 $384.82 $362.79 $337.35 $704.12
La Grande
-pace �r Heat • Other
2026 $36.42 $43.93 $57.88 $250.40 $176.41 $458.27
2027 $37.19 $46.23 $60.26 $254.26 $185.34 $480.90
2028 $37.89 $48.63 $62.69 $257.39 $194.57 $504.56
2029 $38.64 $51.36 $65.30 $261.23 $205.15 $530.09
2030 $39.73 $54.07 $67.93 $268.90 $215.78 $556.56
2031 $40.80 $56.93 $70.67 $276.31 $227.11 $584.33
2032 $41.82 $59.94 $73.52 $283.37 $239.10 $613.44
2033 $69.63 $119.77 $109.23 $288.96 $252.76 $644.75
2034 $71.10 $126.39 $114.24 $295.42 $266.45 $677.11
2035 $73.22 $133.24 $119.40 $305.30 $280.71 $710.96
2036 $75.35 $140.51 $124.84 $315.25 $295.75 $746.63
2037 $77.54 $148.08 $130.50 $325.34 $311.38 $783.95
2038 $80.00 $155.81 $136.28 $336.95 $327.18 $822.36
2039 $83.15 $162.97 $141.76 $352.52 $342.49 $861 .70
2040 $86.43 $170.01 $147.21 $369.03 $357.72 $901.98
2041 $89.83 $177.56 $152.99 $386.23 $374.32 $944.70
2042 $93.32 $185.22 $158.87 $403.74 $391.20 $988.17
2043 $96.87 $193.13 $164.93 $421.53 $408.83 $1,032.79
2044 $100.54 $201.18 $171.12 $439.46 $426.41 $1 ,077.48
2045 $104.32 $209.64 $177.57 $457.56 $444.76 $1 ,123.21
2026 $60.33 $42.36 $94.49 $71.48 $44.12 $55.25
2027 $60.69 $44.83 $98.92 $71.44 $46.25 $58.03
2028 $60.86 $47.53 $103.82 $71.04 $48.63 $60.97
2029 $60.75 $50.51 $109.26 $70.17 $51.28 $64.09
2030 $62.79 $53.56 $115.14 $72.30 $54.17 $67.34
2031 $64.95 $56.82 $121.62 $74.53 $57.37 $70.75
2032 $67.12 $60.38 $128.70 $76.75 $60.90 $74.35
2025 Natural Gas IRP Appendix 335

2033 $100.49 $111.12 $163.37 $79.00 $64.74 $78.15
2034 $102.88 $118.13 $173.08 $81.33 $68.83 $82.14
2035 $106.83 $125.58 $183.65 $84.83 $73.31 $86.33
2036 $110.98 $133.49 $195.08 $88.55 $78.16 $90.73
2037 $115.24 $142.10 $207.54 $92.38 $83.44 $95.38
2038 $119.77 $151.35 $220.93 $96.41 $89.13 $100.21
2039 $124.51 $160.90 $235.11 $100.68 $95.19 $105.23
2040 $130.86 $169.76 $249.61 $106.26 $101.48 $110.30
2041 $137.61 $178.97 $265.06 $112.22 $108.22 $115.61
2042 $144.94 $188.18 $281.30 $118.66 $115.35 $121.00
2043 $152.62 $197.02 $297.70 $125.42 $122.67 $126.41
2044 $160.65 $206.15 $314.85 $132.43 $130.30 $131.85
2045 $168.87 $215.54 $332.44 $139.53 $138.20 $137.36
Year Roseburg
Residential Commercial
Space Heat Water Heat Other Space Heat Water Heat Other
2026 $57.41 $39.48 $92.84 $188.11 $86.32 $197.56
2027 $57.79 $41.78 $97.19 $184.37 $90.99 $207.58
2028 $58.12 $44.25 $101.97 $179.66 $96.00 $218.09
2029 $58.09 $46.92 $107.24 $172.48 $101.41 $229.21
2030 $60.19 $49.66 $112.96 $176.24 $107.11 $240.83
2031 $62.33 $52.72 $119.35 $179.35 $113.48 $253.09
2032 $64.54 $56.05 $126.33 $182.29 $120.49 $266.09
2033 $95.05 $102.07 $158.31 $185.46 $127.96 $279.78
2034 $98.51 $108.46 $167.70 $190.89 $136.00 $294.19
2035 $102.33 $115.56 $178.10 $196.90 $144.79 $309.40
2036 $106.53 $122.74 $189.16 $203.63 $153.82 $325.21
2037 $111.03 $130.34 $201.08 $210.68 $163.40 $341.75
2038 $115.61 $138.83 $214.09 $217.30 $173.90 $359.10
2039 $120.48 $147.31 $227.71 $224.39 $184.65 $376.99
2040 $126.84 $155.58 $241.93 $235.36 $195.64 $395.31
2041 $133.62 $164.11 $257.06 $246.99 $207.18 $414.45
2042 $140.96 $172.55 $272.94 $259.58 $218.91 $433.77
2043 $148.67 $180.65 $289.00 $272.97 $230.55 $453.18
2044 $156.75 $189.03 $305.81 $286.70 $242.50 $472.69
2045 $165.00 $197.59 $323.05 $300.62 $254.65 $492.46
2025 Natural Gas IRP Appendix 336

ALTERNATIVE FUELS AVAILABLE SUPPLY (THOUSANDS OF
DEKATHERMS)
Expected
HydrogenYear Blue Green 1-12- Greenl-12- Microwave
2030 2,667 3,734 3,734 10
2031 3,544 4,957 4,957 14
2032 4,421 6,181 6,181 18
2033 5,299 7,404 7,404 23
2034 6,176 8,628 8,628 27
2035 7,053 91851 9,851 31
2036 7,313 9,672 9,672 194
2037 7,572 9,493 9,493 356
2038 7,832 9,314 9,314 519
2039 8,091 9,136 9,136 681
2040 8,350 10,745 10,745 844
2041 8,447 10,777 10,777 844
2042 8,544 10,810 10,810 845
2043 8,641 10,842 10,842 845
2044 8,738 10,875 10,875 845
2045 8,835 10,907 10,907 846
Year Animal Animal Landfill Landfill Landfill Landfill Landfill
2030 123 185 197 197 395 493 691
2031 158 237 217 217 434 543 760
2032 193 290 236 236 473 591 827
2033 225 338 255 255 510 637 892
2034 251 377 272 272 545 681 953
2035 272 407 289 289 577 722 1,010
2036 286 429 303 303 607 758 1,062
2037 296 445 317 317 633 792 1,108
2038 303 455 329 329 657 821 1,149
2039 308 462 339 339 677 847 1,186
2040 311 467 348 348 695 869 1,217
2041 313 469 356 356 711 888 1,244
2042 314 471 362 362 724 905 1,267
2043 315 473 368 368 735 919 1,286
2044 315 473 372 372 744 930 1,302
2045 316 474 376 376 752 940 1,316
2025 Natural Gas IRP Appendix 337

Year Wastewater Wastewater Wastewater Wastewater Wastewater
2030 7 7 7 36 14
2031 9 9 9 44 18
2032 10 10 10 52 20
2033 12 12 12 59 23
2034 13 13 13 65 26
2035 14 14 14 71 28
2036 15 15 15 75 30
2037 16 16 16 78 31
2038 16 16 16 81 32
2039 16 16 16 83 33
2040 17 17 17 84 34
2041 17 17 17 85 34
2042 17 17 17 86 34
2043 17 17 17 86 35
2044 17 17 17 87 35
2045 18 18 18 87 35
I FFINfa 0 0 0 TV . -: oil = Greenl-12-
2030 42 58 77 58 184
2031 54 103 137 103 253
2032 67 180 240 180 319
2033 77 307 409 307 386
2034 87 501 668 501 401
2035 93 767 1,022 767 400
2036 99 1,082 1,442 1,082 459
2037 102 1,396 1,862 1,396 640
2038 104 1,662 2,216 1,662 762
2039 106 1,856 2,475 1,856 962
2040 107 1,983 2,644 1,983 1,295
2041 108 2,060 2,747 2,060 1,397
2042 108 2,105 2,807 2,105 1,406
2043 108 2,131 2,841 2,131 1,406
2044 109 2,145 2,860 2,145 1,406
2045 109 2,153 2,871 2,153 1,407
Low
Year Blue Green 1-12- Greenl-12- Microwave
. . . -
2030 2,264 3,170 3,170 8
2031 2,831 3,960 3,960 11
2025 Natural Gas IRP Appendix 338

2032 3,398 4,751 4,751 14
2033 3,965 5,541 5,541 17
2034 4,532 6,331 6,331 20
2035 5,099 7,121 7,121 23
2036 5,076 7,263 7,263 119
2037 5,053 71404 7,404 215
2038 5,029 7,546 7,546 311
2039 5,006 7,688 7,688 407
2040 4,983 6,411 6,411 504
2041 4,817 6,155 6,155 483
2042 4,652 5,899 5,899 461
2043 4,486 5,643 5,643 440
2044 4,321 5,386 5,386 419
2045 4,155 5,130 5,130 398
aAnimal Animal Landfill Landfill Landfill Landfill Landfill
2030 105 157 168 168 335 419 587
2031 127 191 177 177 354 442 619
2032 150 224 186 186 372 465 651
2033 169 254 194 194 389 486 680
2034 185 277 202 202 404 505 707
2035 196 295 209 209 417 522 730
2036 199 298 210 210 421 526 736
2037 198 297 211 211 422 528 739
2038 195 293 211 211 422 527 738
2039 191 286 210 210 419 524 733
2040 186 279 208 208 415 519 726
2041 179 268 203 203 405 506 709
2042 172 257 197 197 393 492 689
2043 164 246 191 191 381 476 667
2044 156 234 184 184 368 460 643
2045 149 223 177 177 354 442 619
Year Wastewater Wastewater Wastewater Wastewater Wastewater
2030 6 6 6 31 12
2031 7 7 7 35 14
2032 8 8 8 40 16
2033 9 9 9 45 18
2034 9 9 9 48 19
2035 10 10 10 51 20
2036 10 10 10 52 21
2025 Natural Gas IRP Appendix 339

2037 11 11 11 52 21
2038 10 10 10 52 21
2039 10 10 10 51 20
2040 10 10 10 50 20
2041 10 10 10 49 19
2042 9 9 9 47 19
2043 9 9 9 45 18
2044 8 8 8 43 17
2045 8 8 8 41 16
mo
. . . Waste Biomass Biomass Biomass GreenH2-
•
2030 36 49 65 49 157
2031 44 77 103 77 204
2032 52 132 176 132 247
2033 58 224 298 224 291
2034 64 363 484 363 295
2035 68 554 739 554 289
2036 68 728 971 728 306
2037 68 898 1,197 898 408
2038 67 1,035 1,380 1,035 472
2039 66 1,128 1,504 1,128 583
2040 64 1,183 1,578 1,183 773
2041 62 1,174 1,565 1,174 796
2042 59 1,145 1,526 1,145 764
2043 57 1,105 1,473 1,105 729
2044 54 1,060 1,413 1,060 694
2045 51 1,013 1,350 1,013 662
2025 Natural Gas IRP Appendix 340

COMPLIANCE MECHANISMS AVAILABLE SUPPLY (MTCO2e)
Expected
Year Allowances Allowances Allowance CCI Animal Animal
(Free) (Given) Manure 4 Manure
2026 160,206 640,824 4,310,970 91,348 19,471 29,207
2027 108,473 614,679 3,891,848 91,212 29,382 44,073
2028 64,527 580,747 3,472,726 121,331 39,293 58,939
2029 28,370 539,026 3,053,604 120,727 49,203 73,805
2030 0 489,518 2,634,482 120,349 59,114 88,671
2031 0 469,492 2,516,058 119,826 73,349 110,023
2032 0 449,467 2,397,633 119,601 87,583 131,375
2033 0 429,441 2,279,209 119,122 101,818 152,727
2034 0 409,415 2,160,785 118,804 116,052 174,079
2035 0 389,389 2,042,361 118,908 130,287 195,430
2036 0 369,364 1,923,936 119,058 134,074 201,111
2037 0 349,338 1,805,512 118,670 137,862 206,792
2038 0 329,312 1,687,088 118,296 141,649 212,473
2039 0 309,287 1,568,664 117,769 145,436 218,154
2040 0 289,261 1,450,239 117,622 149,223 223,835
2041 0 269,235 1,331,815 117,371 149,688 224,532
2042 0 249,209 1,213,391 116,961 150,152 225,228
2043 0 220,283 1,103,867 116,752 150,616 225,925
2044 0 191,357 994,343 116,723 151,081 226,621
2045 0 162,431 884,819 116,418 151,545 227,318
Year Landfill Gas Landfill Gas Landfill Gas Landfill Gas 01101111 "01
KM M(RT C) (RTC) (RTC) (RTC)
2026 44,457 44,457 88,915 88,915 177,830
2027 50,976 50,976 101,953 101,953 203,905
2028 57,495 57,495 114,990 114,990 229,981
2029 64,014 64,014 128,028 128,028 256,056
2030 70,533 70,533 141,066 141,066 282,132
2031 77,052 77,052 154,104 154,104 308,208
2032 83,571 83,571 167,142 167,142 334,283
2033 90,090 90,090 180,179 180,179 360,359
2034 96,609 96,609 193,217 193,217 386,434
2035 103,128 103,128 206,255 206,255 412,510
2036 107,352 107,352 214,704 214,704 429,408
2037 111,577 111,577 223,153 223,153 446,307
2038 115,801 115,801 231,603 231,603 463,205
2025 Natural Gas IRP Appendix 341

2039 120,026 120,026 240,052 240,052 480,104
2040 124,251 124,251 248,501 248,501 497,002
2041 126,276 126,276 252,551 252,551 505,102
2042 128,301 128,301 256,601 256,601 513,203
2043 130,326 130,326 260,651 260,651 521,303
2044 132,351 132,351 264,702 264,702 529,403
2045 134,376 134,376 268,752 268,752 537,503
Year Wastewater Wastewater Wastewater Wastewater Wastewa
(RTC) (RTC) (RTC) (RTC) (RTC;i
2026 924 924 924 3,234 3,234
2027 1,269 1,269 1,269 4,440 4,440
2028 1,613 1,613 1,613 5,646 5,646
2029 1,958 1,958 1,958 6,853 6,853
2030 2,303 2,303 2,303 8,059 8,059
2031 2,748 2,748 2,748 9,618 9,618
2032 3,193 3,193 3,193 11,177 11,177
2033 3,639 3,639 3,639 12,736 12,736
2034 4,084 4,084 4,084 14,295 14,295
2035 4,530 4,530 4,530 15,854 15,854
2036 4,702 4,702 4,702 16,457 16,457
2037 4,874 4,874 4,874 17,060 17,060
2038 5,047 5,047 5,047 17,664 17,664
2039 5,219 5,219 5,219 18,267 18,267
2040 5,392 5,392 5,392 18,871 18,871
2041 5,427 5,427 5,427 18,993 18,993
2042 5,462 5,462 5,462 19,116 19,116
2043 5,497 5,497 5,497 19,238 19,238
2044 5,532 5,532 5,532 19,361 19,361
2045 5,567 5,567 5,567 19,484 19,484
Year . . . i0
Waste 3 Industrial Industrial Industrial
2026 5,353 0 0 0
2027 8,078 0 0 0
2028 10,803 0 0 0
2029 13,528 0 0 0
2030 16,252 0 0 0
2031 20,166 0 0 0
2032 24,080 0 0 0
2033 27,993 0 0 0
2025 Natural Gas IRP Appendix 342

2034 31,907 0 0 0
2035 35,820 11,657 5,791 4,788
2036 36,862 23,320 11,586 9,580
2037 37,903 34,991 17,383 14,374
2038 38,944 46,667 23,184 19,170
2039 39,985 58,350 28,989 23,969
2040 41,027 70,040 34,796 28,771
2041 41,154 70,030 34,791 28,767
2042 41,282 70,020 34,786 28,763
2043 41,410 70,010 34,781 28,759
2044 41,537 70,000 34,776 28,755
2045 41,665 69,990 34,771 28,751
00 00 800- Direct Air
Industrial Industrial Industrial
2026 0 0 0 0
2027 0 0 0 0
2028 0 0 0 0
2029 0 0 0 0
2030 0 0 0 0
2031 0 0 0 0
2032 0 0 0 0
2033 0 0 0 0
2034 0 0 0 0
2035 7,270 17,598 28,136 136,289
2036 14,544 35,205 56,287 300,259
2037 21,823 52,823 84,454 491,909
2038 29,105 70,450 112,637 711,240
2039 36,391 88,087 140,836 958,252
2040 43,682 105,735 169,051 1,232,944
2041 43,676 105,720 169,027 1,314,253
2042 43,669 105,704 169,002 1,395,562
2043 43,663 105,689 168,978 1,476,871
2044 43,657 105,674 168,954 1,558,180
2045 43,651 105,659 168,930 1,639,488
Low
Year Animal Manure 4 lip Animal Manure 5 . . . Waste 3
2026 89,623 171494 26,240 4,810
2027 89,442 25,667 38,500 7,057
2028 119,094 33,840 50,759 9,304
2025 Natural Gas IRP Appendix 343

2029 118,107 42,012 63,019 11,551
2030 117,369 50,185 75,278 13,798
2031 116,651 58,987 88,480 16,217
2032 116,037 67,787 101,681 18,637
2033 115,223 76,587 114,880 21,056
2034 114,458 85,386 128,079 23,476
2035 114,209 94,185 141,278 25,895
2036 114,106 93,158 139,738 25,612
2037 113,465 92,130 138,195 25,330
2038 112,687 91,101 136,652 25,047
2039 111,885 90,071 135,107 24,764
2040 111,355 89,041 133,561 24,480
2041 110,682 85,489 128,234 23,504
2042 110,005 81,937 122,906 22,527
2043 109,135 78,384 117,576 21,550
2044 108,625 74,829 112,244 20,573
2045 107,752 71,274 106,911 19,596
Year Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas
2026 41,564 41,564 83,128 83,128 166,256
2027 46,143 46,143 92,286 92,286 184,573
2028 50,722 50,722 101,444 101,444 202,889
2029 55,301 55,301 110,602 110,602 221,204
2030 59,879 59,879 119,759 119,759 239,518
2031 62,815 62,815 125,630 125,630 251,260
2032 65,750 65,750 131,500 131,500 263,000
2033 68,684 68,684 137,369 137,369 274,737
2034 71,618 71,618 143,236 143,236 286,473
2035 74,552 74,552 149,103 149,103 298,206
2036 74,471 74,471 148,941 148,941 297,883
2037 74,389 74,389 148,778 148,778 297,556
2038 74,307 74,307 148,613 148,613 297,226
2039 74,223 74,223 148,447 148,447 296,893
2040 74,140 74,140 148,279 148,279 296,558
2041 71,953 71,953 143,906 143,906 287,813
2042 69,766 69,766 139,532 139,532 279,064
2043 67,578 67,578 135,156 135,156 270,311
2044 65,389 65,389 130,778 130,778 261,556
2045 63,199 63,199 126,398 126,398 252,797
2025 Natural Gas IRP Appendix 344

Year Wastewater Wastewater Wastewater Wastewater Wastewater
2026 843 843 843 2,950 2,950
2027 1,121 1,121 1,121 3,923 3,923
2028 1,399 1,399 1,399 4,896 4,896
2029 1,677 1,677 1,677 5,869 5,869
2030 1,955 1,955 1,955 6,842 6,842
2031 2,219 2,219 2,219 7,766 7,766
2032 2,483 2,483 2,483 8,689 8,689
2033 2,747 2,747 2,747 9,613 9,613
2034 3,011 3,011 3,011 10,537 10,537
2035 3,274 3,274 3,274 11,461 11,461
2036 3,263 3,263 3,263 11,421 11,421
2037 3,252 3,252 3,252 11,381 11,381
2038 3,240 3,240 3,240 11,341 11,341
2039 3,229 3,229 3,229 11,300 11,300
2040 3,217 3,217 3,217 11,260 11,260
2041 3,097 3,097 3,097 10,841 10,841
2042 2,978 2,978 2,978 10,422 10,422
2043 2,858 2,858 2,858 10,002 10,002
2044 2,738 2,738 2,738 9,583 9,583
2045 2,618 2,618 2,618 9,163 9,163
2025 Natural Gas IRP Appendix 345

APPENDIX 7.1 : WA GRC REQUIREMENTS
For its Washington service territory, Avista agreed to include in its 2025 Natural Gas IRP, a
natural gas system decarbonization plan for complying with the Climate Commitment Act (CCA)
with the following elements.
i. The Natural Gas IRP's decarbonization plan shall include a supply curve of
decarbonization resources by price and availability, e.g. energy efficiency bundle 1 costs
X$/ton of carbon dioxide equivalent (CO2e) reduction and can reduce Y tons of CO2e,
dairy RNG costs A$/ton and can reduce B tons of CO2e.
The Avista 2025 Natural Gas IRP has included a variety of supplies to decarbonize its energy
delivered to the end user based on inputs from ICF (Appendix 6.1). The resources in Figures 1
to Figure 8 below show those supply side or demand side options (energy efficiency) available
to the model to meet climate goals as laid out in the CCA. Each figure represents the cost per
metric ton of carbon dioxide equivalent combined with the estimated potential of the resource
over time.
Figure 1: RNG —Animal Manure and Food Waste (Modeled in 2025 IRP)
30,000
RNG - AM 4
25,000 RNG - AM 5
• RNG - FW 3
•
20,000 •
a, •
O
U 15,000 - 00
10,000 •
5,000
$- $200 $400 $600 $800 $1,000 $1,200
Real2026 $ per MTCO2e
2025 Natural Gas IRP Appendix 346

Figure 2: RNG — Landfill Gas (Modeled in 2025 IRP)
60,000
• RNG - LFG 1
• RNG - LFG 2
50,000 • RNG - LFG 3
• • RNG - LFG 4
40,000 • RNG - LFG 5
a�
N •
30,000
20,000
10,000
$- $200 $400 $600 $800
Rea12026 $ per MTCO2e
Figure 3: RNG —Waste Water (Modeled in 2025 IRP)
5,000
• RNG - WWI
4,500
RNG - WW2
4,000 • RNG - WW 3
•
3,500 • - RNG - WW 4
N 3,000 • RNG - WW 5
2,500
2,000
1,500
1,000
500
$- $200 $400 $600 $800 $1,000 $1,200
Real2026 $ per MTCO2e
2025 Natural Gas IRP Appendix 347

-figure 4: Green Hydrogen by Production Type (Modeled in 2025 IRP)
700,000
Blue Hydrogen 1
600,000 Green H2-Wind+Electrolysis 1
• Green H2-Solar+Electrolysis 1
500,000 Microwave Pyrolysis 1 ,
N 400,000
0
U
300,000
200,000 •
100,000
$- $200 $400 $600 $800 $1,000
Real2026 $ per MTCO2e
Figure 5: Synthetic Methane by Process Type (Modeled in 2025 IRP)
160,000 • Biomass 1
140,000 • Biomass 2
• • Biomass 3
120,000 • • Green H2-BiogenicCO21
a�
100,000
N w •
80,000
60,000 • •• •
40,000 • • •
20,000 •
w
$- $200 $400 $600 $800 $1,000 $1,200
Real2026 $ per MTCO2e
2025 Natural Gas IRP Appendix 348

Figure 6: CCUS (Modeled in 2025 IRP)
1,800,000 . under 25Dth/hr-Industrial CCUS
1,600,000 25-50 Dth/hr-Industrial CCUS - •
•
1,400,000 • 50-100 Dth/hr-Industrial CCUS
100-200 Dth/hr-Industrial CCUS •
1,200,000 •
200-400 Dth/hr-Industrial CCUS •
a� •
0 1,000,000 800-1600 Dth/hr-Industrial CCUS •
U •
800,000 • Direct Air Capture-DAC CCUS •
600,000
400,000 1
200,000
ii• • • • • • •�••�•
$- $10 $20 $30 $40 $50
Rea 12026 $ per MTCO2e
Figure 7: Renewable Thermal Credits - (Modeled in 2025 IRP)
600,000
• RTC (AM 4) • RTC (AM 5)
• RTC (FW 3) • RTC (LFG 1)
500,000 • RTC (LFG 2) • RTC (LFG 3)
• RTC (LFG 5) • RTC (WW 1)
400,000 • • RTC (WW 2) • RTC (WW 3)
N • RTC (WW 4) • RTC (WW 5)
300,000 •
•
200,000 •
•
100,000
$- $500 $1,000 $1,500 $2,000
Rea12026 $ per MTCO2e
2025 Natural Gas IRP Appendix 349

Energy Efficiency is based on the 2025 year of the study provided by AEG as discussed in
Chapter 4 and found in Appendix 4.
Figure 8: Energy Efficiency WA CPA- (Modeled in 2025 IRP)
40,000 • Commercial
35,000 • Industrial
• • Residential
30,000 ; • Transport
•
25,000 •
N •
20,000 •
H
15,000
10,000 �0
5,000
0
$0 $200 $400 $600 $800
Real 2026$ per MTCO2e
ii. The decarbonization plan shall consider a comprehensive set of strategies, programs,
incentives and other measures to encourage new and existing customers to adopt fully
energy efficient appliances and equipment or other decarbonization measures, which
could include electrification.
Chapter 4 includes a summary of the demand side resources considered in the 2025 IRP,
including electrification. Chapter 2 discusses the Preferred Resource Strategy selected in the
IRP to meet the CCA requirements, and ultimately the Company's decarbonization plan for this
IRP. Appendix 4 has all Conservation Potential Assessments (CPAs) included for a full analysis
of considerations.
iii. The decarbonization plan shall include targets for the ratio of new gas customers
added relative to new electric customers added in future years.
This is updated in the "No Growth" case and includes no new customers after 2025 in
Washington. If no new gas customers are added to the system, the ratio would be 0 as the
numerator would be 0 in the following equation.
Ratio of New Gas Customers to New Electric Customers = New Gas Customers
New Electric Customers
2025 Natural Gas IRP Appendix 350

Because the ratio of new gas customers relative to new electric customers is already expected
to be 0, any such future target would also be 0.
2025 Natural Gas IRP Appendix 351

Impact Results Overview
Dollar Year is 2025 Aggregation Scheme is 546 Unaggregated Run ID is 469772
Economic Indicators by Impact Tax Results
Impact I Employment Labor Income Value Added I Output
Sub County Sub County
1 -Direct 85.53 $4,162,180.24 I $6,759,802.36 I $17,718,078.00 Impact General Special Districts County State Federal Total
2- Indirect I 28.46 $2,236,288.43 $3,566,643.49 $7,108,142.73
3-Induced 29.49 I $1,803,670.28 $3,219,959.99 $5,383,365.82 1 -Direct $130,883.46 $206,378.30 $80,029.15 $425,305.41 $970,538.43 $1,813,134.76
Totals 143.48 $8,202,138.94 $13,546,405.83 $30,209,586.55 2-Indirect $50,628.72 $79,831.74 $31,393.79 $190,258.99 $527,138.23 $879,251.46
3-Induced $43,066.25 I $67,907.19 $27,185.87 I $163,274.54 $444,710.79 I $746,144.65
Totals $224,578.43 $354,117.23 $138,608.81 $778,838.95 $1,942,387.45 $3,438,530.86
Direct Leakages Industries by Impact Output as Percentage of Total Industry Output
Institutional Commodity Sales I Margin I Imports to Region Percentage of Total
Display Code Display Description Industry Total Output Impact Output
N/A N/A N/A Industry Output
i
1 51 Construction of new m... $1,344,152,784.86 $12,598,078.00 .94%
2 48 Natural gas distribution $1,906,556,996.63 $5,155,971.77 .27%
3 419 Pipeline transportation $156,242,741.16 $123,034.89 .08%
4 20 Oil and gas extraction $643,903,195.65 $354,416.08 .06%
Top 15 Industries by Impact Output as Percentage of Total Industry Output 5 204 Ready-mix concrete m... $439,124,561.31 $217,187.39 .05%
6 207 Other concrete produ... $166,556,410.77 $63,370.09 .04%
7 198 Brick,tile,and other st... $99,204,424.51 $29,345.95 .03%
$1,500,000,000.00 8 28 Stone mining and qua... $302,406,487.17 $87,046.64 .03%
9 213 Mineral wool manufac... $81,621,617.02 $20,428.42 .03%
10 258 Fabricated pipe and pi... $177,207,749.67 $39,640.15 .02%
$1,000,000,000.00 11 259 Other fabricated meta... $411,069,682.32 $75,512.28 .02%
12 453 Commercial and indus... $1,044,986,005.77 $167,286.64 .02%
$500,000,000.00 13 29 Sand and gravel mining $315,791,799.63 $44,312.48 .01%
14 142 Prefabricated woodb... $134,689,047.99 $18,634.24 .01%
$0.00 15 238 Meta l window and doo... $89,674,106.08 $11,926.55 .01%
�: �: �.. �.• a: �: a: 16 203 Cement manufacturing $85,469,875.76 $10,249.45 .01%
a\ ash. e+ `°. `�� a� �a. o°�. ��. \`a a� a�,
�o a� X+ e �� ea pt ��� 40 °a \tea 17 395 Wholesale-Machiner... $3,042,830,238.32 $362,140.62 .01%
eta\ ���a� eta "e a�a aka �a��\ �a�� 18 401 Wholesale-WholesaI... $1,265,851,456.47 $142,923.69 .01%
O`rAs"
L O 19 30 Other clay,ceramic, r... $19,990,917.12 $2,217.62 .01%
�4' ��� LO LOB L01 �oi4' L4' ��3 y�4' L�� R�i� LQi �pti L'�0
20 31 Potash,soda,and bor... $22,363,200.86 $2,469.98 .01%
Industry Total Output At Impact Output 21 214 Miscellaneous nonme... $31,026,925.41 $3,146.23 .01%
t
22 156 Asphalt shi ngle and co... $679,811,541.45 $68,669.89 .01%
Generated by Looker on March 7, 2025 at 12:04 PM EST 2025 Natural Gas IRP Appendix 352

Impact Results Overview
Dollar Year is 2025 Aggregation Scheme is 546 Unaggregated Run ID is 469780
Economic Indicators by Impact Tax Results
Impact ^ I Employment Labor Income Value Added I Output
Sub County Sub County
1 -Direct 117.38 $4,739,489.73 I $7,598,313.26 $22,568,905.26 Impact ^ General Special Districts County State Federal Total
2-Indirect I 35.16 $2,767,633.46 $4,445,541.01 $8,837,562.04
3-Induced 34.70 $2,121,946.06 I $3,788,286.14 $6,333,540.51 1 -Direct $141,536.34 $223,175.82 $86,632.57 $474,625.45 $1,080,375.42 $2,006,345.60
Totals 187.24 I $9,629,069.26 $15,832,140.41 $37,740,007.82 2-Indirect $64,505.53 $101,712.81 $39,975.00 $238,788.42 $654,519.80 $1,099,501.55
3-Induced I $50,669.85 I $79,896.62 I $31,985.70 $192,092.93 I $523,188.51 $877,833.61
Totals $256,711.72 $404,785.25 $158,593.26 $905,506.80 $2,258,083.73 $3,983,680.77
Direct Leakages I F Industries by Impact Output as Percentage of Total Industry Output
Institutional Commodity Sales I Margin I Imports to Region Percentage of Total
Display Code Display Description Industry Total Output Impact Output
N/A N/A N/A Industry Output
1 51 Construction of new m... $1,344,152,784.86 $17,534,612.52 1.30%
2 48 Natural gas distribution $1,906,556,996.63 $5,077,422.98 .27%
3 419 Pipeline transportation $156,242,741.16 $121,840.71 .08%
4 204 Ready-mix concrete m... $439,124,561.31 $301,661.67 .07%
Top 15 Industries by Impact Output as Percentage of Total Industry Output 5 20 Oil and gas extraction $643,903,195.65 $350,501.47 .05%
6 207 Other concrete produ... $166,556,410.77 $87,984.50 .05%
7 198 Brick,tile,and other st... $99,204,424.51 $40,765.54 .04%
$1,500,000,000.00 8 28 Stone mining and qua... $302,406,487.17 $120,748.53 .04%
9 213 Mineral wool manufac... $81,621,617.02 $28,390.88 .03%
10 1258 Fabricated pipe and pi... $177,207,749.67 $55,117.09 .03%
$1,000,000,000.00 11 259 Other fabricated meta... $411,069,682.32 $104,437.75 .03%
12 453 Commercial and indus... $1,044,986,005.77 $224,346.61 .02%
$500,000,000.00 13 29 Sand and gravel mining $315,791,799.63 $61,526.55 .02%
14 142 Prefabricated wood b... $134,689,047.99 $25,837.27 .02%
$0.00 - 15 238 Metal window and doo... $89,674,106.08 $16,541.91 .02%
off' ��' h:. o e� �' a 16 203 Cement manufacturing $85,469,875.76 $14,052.74 .02%
o� 5a tam +o �e+ got a� o o° a� i�� a� a° o
a e ao o �� 17 395 Wholesale-Machiner... $3,042,830,238.32 $497,489.21 .02/0
�a� o
��Q ` °�� `fie ape re °� �6 �e� era 18 30 Other clay,ceramic, r... $19,990,917.12 $3,075.36 .02/0
O �� �` O C, �a Q 19 31 Potash,soda,and bor... $22,363,200.86 $3,429.37 .02%
20 214 Miscellaneous nonme... $31,026,925.41 $4,366.88 .01%
t Industry Total Output At Impact Output 21 156 Asphalt shingle and co... $679,811,541.45 $94,989.03 .01%
22 206 Concrete pipe manufa... $22,393,029.90 $2,935.95 .01%
1 i i
Generated by Looker on March 7, 2025 at 12:05 PM EST 2025 Natural Gas IRP Appendix 353

Impact Results Overview
Dollar Year is 2025 Aggregation Scheme is 546 Unaggregated Run ID is 471189
Economic Indicators by Impact Tax Results
Impact I Employment Labor Income Value Added I Output
Sub County Sub County
1 -Direct 120.93 I $3,815,920.37 $5,619,728.73 I $20,427,613.81 Impact General Special Districts County State Federal Total
2- Indirect I 29.91 $2,364,127.37 $3,853,802.08 $7,621,726.95
3-Induced 28.72 $1,755,340.79 $3,133,965.52 $5,239,605.30 1 -Direct $84,247.99 $132,842.85 $51,777.39 $334,877.74 $821,118.38 $1,424,864.35
Totals 179.56 $7,935,388.53 $12,607,496.33 $33,288,946.06 2-Indirect $58,412.83 $92,105.82 $36,158.34 $209,932.82 $562,917.98 $959,527.78
3-Induced I $41,921.21 I $66,101.69 I $26,463.05 I $158,914.60 I $432,803.42 I $726,203.97
Totals $184,582.03 $291,050.37 $114,398.77 $703,725.16 $1,816,839.78 $3,110,596.10
Direct Leakages I F Industries by Impact Output as Percentage of Total Industry Output
Institutional Commodity Sales I Margin I Imports to Region Percentage of Total
Display Code Display Description Industry Total Output Impact Output
N/A N/A N/A Industry Output
1 51 Construction of new m... $1,344,152,784.86 $18,461,861.08 1.37%
2 48 Natural gas distribution $1,906,556,996.63 $2,001,430.80 .10%
3 204 Ready-mix concrete m... $439,124,561.31 $316,711.32 .07%
4 207 Other concrete produ... $166,556,410.77 $92,332.25 .06%
Top 15 Industries by Impact Output as Percentage of Total Industry Output 5 198 Brick,tile,and other st... $99,204,424.51 $42,811.54 .04%
6 28 Stone mining and qua... $302,406,487.17 $126,538.07 .04%
7 213 Mineral wool manufac... $81,621,617.02 $29,833.49 .04%
$1,500,000,000.00 8 258 Fabricated pipe and pi... $177,207,749.67 $57,949.53 .03%
9 419 Pipeline transportation $156,242,741.16 $49,625.25 .03%
10 259 Other fabricated meta... $411,069,682.32 $108,946.63 .03%
$1,000,000,000.00 11 20 Oil and gas extraction $643,903,195.65 $141,642.42 .02%
12 453 Commercial and indus... $1,044,986,005.77 $223,303.26 .02%
$500,000,000.00 13 29 Sand and gravel mining $315,791,799.63 $64,563.57 .02%
14 142 Prefabricated wood b... $134,689,047.99 $27,062.93 .02%
$0.00 15 238 Metal window and doo... $89,674,106.08 $17,333.71 .02%
16 203 Cement manufacturing $85,469,875.76 $14,463.50 .02%
rLoo�� Lej oIQ, tea ff.
17 395 Wholesale-Machiner... $3,042,830,238.32 $514,086.42 .02%a e
�¢O t o� a `a� fie � kO
�c� &f \` a 18 30 Other clay,ceramic,r... $19,990,917.12 $3,221.73 .02%
t ,'<cea`
B o ` ° Q\QO 19 31 Potash,soda,and bor... $22,363,200.86 $3,598.59 .02%
4 -0
V b
o
20 214 Miscellaneous nonme... $31,026,925.41 $4,580.31 .01 /o
Industry Total Output � Impact Output 21 156 Asphalt shingle and co... $679,811,541.45 $99,161.04 .01%
t
22 239 Sheet metal work man... $398,959,709.39 $54,732.54 .01
Generated by Looker on March 7, 2025 at 12:00 PM EST 2025 Natural Gas IRP Appendix 354

Impact Results Overview
Dollar Year is 2025 Aggregation Scheme is 546 Unaggregated Run ID is 469771
Economic Indicators by Impact Tax Results
Impact I Employment Labor Income Value Added I Output
i Sub County Sub County
1 -Direct 79.80 $3,845,973.13 $7,348,981.09 I $17,491,756.24 Impact General Special Districts County State Federal Total
2- Indirect I 21.34 $1,984,149.41 $3,650,814.15 $6,599,875.68
3-Induced 21.11 $1,479,580.49 $2,965,479.08 $4,692,962.93 1 -Direct $109,444.11 $173,406.05 $88,410.22 $689,515.20 $1,026,766.59 $2,087,542.17
I I
Totals 122.25 $7,309,703.03 $13,965,274.32 $28,784,594.86 2-Indirect $39,486.93 $62,537.90 $31,895.90 $254,863.32 $525,351.58 $914,135.64
3-Induced $34,893.35 $55,275.12 I $28,186.97 $223,542.53 I $405,293.57 $747,191.54
Totals $183,824.39 $291,219.08 $148,493.09 $1,167,921.05 $1,957,411.74 $3,748,869.34
Direct Leakages Industries by Impact Output as Percentage of Total Industry Output
Institutional Commodity Sales I Margin I Imports to Region Percentage of Total
Display Code Display Description Industry Total Output Impact Output
N/A N/A N/A Industry Output
1 51 Construction of new m... $2,530,323,556.97 $12,459,429.25 .49%
2 48 Natural gas distribution $1,330,211,506.84 $5,046,192.74 .38%
3 204 Ready-mix concrete m... $1,382,819,907.83 $312,396.09 .02%
4 258 Fabricated pipe and pi... $56,901,593.63 $12,578.61 .02%
Top 15 Industries by Impact Output as Percentage of Total Industry Output 5 198 Brick,tile,and other st... $39,535,932.51 $7,513.57 .02%
6 207 Other concrete produ... $463,711,805.08 $86,556.01 .02%
7 419 Pipeline transportation $313,522,399.18 $55,914.00 .02%
$2,000,000,000.00 8 203 Cement manufacturing $178,949,927.04 $30,390.79 .02%
9 259 Other fabricated meta... $205,136,969.53 $34,583.60 .02%
10 213 Mineral wool manufac... $32,488,615.29 $5,380.82 .02%
11 28 Stone mining and qua... $380,145,469.54 $61,973.22 .02%
$1,000,000,000.00 12 29 Sand and gravel mining $376,320,589.30 $41,064.53 .01%
13 142 Prefabricated wood b... $109,244,417.23 $11,743.00 .01%
14 131 Potash,soda,and bor... $8,583,366.19 $909.45 .01%
$0.00 15 238 Meta l window and doo... $236,236,819.31 $24,522.99 .01%
�; �: a: �,• �: 16 156 Asphalt shingle and co... $498,902,678.66 $51,528.86 .01%
a� .�a o°� �Oa �a� yea a a a°� o
Qi �a 17 239 Sheet metal work man... $1,098,706,441.07 $82,150.51 .01 /o
.��\ 18 1240 Ornamental and archi... $293,878,195.34 $21,394.14 .01%
Q`Qe `eF Or
L Q 19 395 Wholesale-Machiner... $5,520,331,451.56 $341,206.25 .01%
20 453 Commercial and indus... $3,346,058,055.32 $202,699.14 .01%
Industry Total Output � Impact Output 21 236 Fabricated structural ... $696,129,833.35 $41,756.92 .01%
t
22 34 Other nonmetallic min... $8,275,559.30 $482.84 .01%
Generated by Looker on March 7, 2025 at 12:01 PM EST 2025 Natural Gas IRP Appendix 355

Impact Results Overview
Dollar Year is 2025 Aggregation Scheme is 546 Unaggregated Run ID is 469778
Economic Indicators by Impact Tax Results
Impact ^ I Employment Labor Income Value Added I Output
I I Sub County Sub County
1 -Direct 112.25 $4,523,026.49 I $8,469,733.12 $22,851,574.00 Impact ^ General Special Districts County State Federal Total
2-Indirect I 27.88 $2,585,686.32 $4,795,959.70 $8,743,936.28
3-Induced 25.73 I $1,802,918.39 $3,613,334.72 I $5,718,291.24 1 -Direct $119,077.67 $188,654.12 $96,188.89 $749,302.99 $1,184,064.82 $2,337,288.49
Totals 165.86 $8,911,631.21 $16,879,027.54 $37,313,801.52 2-Indirect $53,029.07 $83,989.01 $42,835.14 $341,779.80 $686,946.75 $1,208,579.77
3-Induced $42,510.50 $67,341.55 $34,340.12 $272,343.92 $493,853.13 $910,389.23
Totals I $214,617.24 $339,984.68 $173,364.15 $1,363,426.72 $2,364,864.70 $4,456,257.49
Direct Leakages Industries by Impact Output as Percentage of Total Industry Output
Institutional Commodity Sales I Margin I Imports to Region Percentage of Total
Display Code Display Description Industry Total Output Impact Output
N/A N/A N/A Industry Output
1 151 Construction of new m... $2,530,323,556.97 $17,729,574.00 .70%
2 48 Natural gas distribution $1,330,211,506.84 $5,139,810.02 .39%
3 204 Ready-mix concrete m... $1,382,819,907.83 $443,872.25 .03%
4 258 Fabricated pipe and pi... $56,901,593.63 $17,885.66 .03%
Top 15 Industries by Impact Output as Percentage of Total Industry Output 5 198 Brick,tile,and other st... $39,535,932.51 $10,675.41 .03%
6 207 Other concrete produ... $463,711,805.08 $122,939.63 .03%
7 203 Cement manufacturing $178,949,927.04 $43,129.73 .02%
$2,000,000,000.00 8 259 Other fabricated meta... $205,136,969.53 $48,980.73 .02%
9 213 Mineral wool manufac... $32,488,615.29 $7,648.28 .02%
10 28 Stone mining and qua... $380,145,469.54 $87,983.78 .02%
11 419 Pipeline transportation $313,522,399.18 $57,990.38 .02%
$1,000,000,000.00 12 29 Sand and gravel mining $376,320,589.30 $58,334.48 .02%
13 142 Prefabricated wood b... $109,244,417.23 $16,665.14 .02%
14 31 Potash,soda,and bor... $8,583,366.19 $1,291.44 .02%
$0.00 15 238 Metal window and doo... $236,236,819.31 $34,803.65 .01%
off' �:' �: 16 156 Asphalt shingle and co... $498,902,678.66 $72,999.56 .01%
P g
\o� a�a +` eat a� °� �a got`` s�°o ��kO KSa� �a aye as a° o
a� X� 17 239 Sheet metal work man... $1,098,706,441.07 $116,734.27 .01 /o
18 240 Ornamental and a rc h i... $293,878,195.34 $30,320.69 .01%
L �w Q �a Q Qo 19 395 Wholesale-Machiner... $5,520,331,451.56 $482,445.15 .01%
20 236 Fabricated structural ... $696,129,833.35 $59,039.10 .01%
t Industry Total Output ift Impact Output 21 453 Commercial and indus... $3,346,058,055.32 $281,628.05 .01%
22 34 Other nonmetallic min... $8,275,559.30 $684.38 .01%
Generated by Looker on March 7, 2025 at 12:03 PM EST 2025 Natural Gas IRP Appendix 356

Impact Results Overview
Dollar Year is 2025 Aggregation Scheme is 546 Unaggregated Run ID is 483707
Economic Indicators by Impact Tax Results
Impact ^ I Employment Labor Income Value Added I Output
Sub County Sub County
1 -Direct 114.73 $3,703,271.79 I $6,098,436.03 I $20,427,613.81 Impact ^ General Special Districts County State Federal Total
2-Indirect I 24.88 $2,297,316.43 $4,331,025.36 $8,028,273.81
3-Induced 21.61 $1,514,515.94 I $3,038,825.37 $4,810,238.81 1 -Direct $63,737.14 $103,529.22 $52,152.08 $398,091.70 $912,081.69 $1,529,591.82
Totals 161.23 $7,515,104.16 $13,468,286.77 $33,266,126.43 2-Indirect $50,154.89 $81,501.08 $41,047.66 $318,254.24 $614,223.60 $1,105,181.47
3-Induced I $35,906.00 I $58,353.11 I $29,386.97 I $227,056.51 I $414,774.49 I $765,477.08
Totals $149,798.03 $243,383.41 $122,586.70 $943,402.45 $1,941,079.78 $3,400,250.37
Direct Leakages Industries by Impact Output as Percentage of Total Industry Output
Institutional Commodity Sales I Margin I Imports to Region Percentage of Total
Display Code Display Description Industry Total Output Impact Output
N/A N/A N/A Industry Output
1 151 Construction of new m... $2,530,323,556.97 $18,461,861.08 .73%
2 48 Natural gas distribution $1,330,211,506.84 $1,981,514.46 .15%
3 204 Ready-mix concrete m... $1,382,819,907.83 $461,255.53 .03%
4 258 Fabricated pipe and pi... $56,901,593.63 $18,604.11 .03%
Top 15 Industries by Impact Output as Percentage of Total Industry Output 5 198 Brick,tile,and other st... $39,535,932.51 $11,088.31 .03%
6 207 Other concrete produ... $463,711,805.08 $127,657.13 .03%
7 203 Cement manufacturing $178,949,927.04 $44,737.70 .03%
$2,000,000,000.00 8 259 Other fabricated meta... $205,136,969.53 $50,638.26 .02%
9 213 Mineral wool manufac... $32,488,615.29 $7,952.27 .02%
10 28 Stone mining and qua... $380,145,469.54 $91,313.64 .02%
11 29 Sand and gravel mining $376,320,589.30 $60,629.45 .02%
$1,000,000,000.00 12 ' 142 Prefabricated wood b... $109,244,417.23 $17,256.91 .02%
13 31 Potash,soda,and bor... $8,583,366.19 $1,328.83 .02%
14 238 Metal window and doo... $236,236,819.31 $36,103.06 .02%
$0.00 15 156 Asphalt shingle and co... $498,902,678.66 $75,533.40 .02%
off' ��' o �:' a' �� �: a� :' a ' �: a:' a:' A:' 16 239 Sheet metal work man... $1,098,706,441.07 $121,295.27 .01%
\off a�a +` eaQ �a� �a •pt`` °° awe aa, 17 240 Ornamental and archi... $293,878,195.34 $31,393.32 .01%
a\� `ate XN e�� ��a �Z\ �a4O �
e
18 395 Wholesale-Machiner... $5,520,331,451.56 $498,170.73 .01%
N
Qo 19 236 Fabricated structural ... $696,129,833.35 $60,853.94 .01 /'05 05 '' (0
'��
20 34 Other nonmetallic min... $8,275,559.30 $708.85 .01%
t Industry Total Output ift Impact Output 21 453 Commercial and indus... $3,346,058,055.32 $282,791.92 .01%
22 206 Concrete pipe manufa... $50,146,410.93 $4,113.85 .01%
1 i i
Generated by Looker on March 7, 2025 at 11:57 AM EST 2025 Natural Gas IRP Appendix 357

APPENDIX 10.1: DISTRIBUTION SYSTEM MODELING
OVERVIEW
The primary goal of distribution system planning is to design for present needs and to plan for future
expansion in order to serve demand growth. This allows Avista to satisfy current demand-serving
requirements,while taking steps toward meeting future needs. Distribution system planning identifies
potential problems and areas of the distribution system that require reinforcement. By knowing when and
where pressure problems may occur,the necessary reinforcements can be incorporated into normal
maintenance. Thus,more costly reactive and emergency solutions can be avoided.
COMPUTER MODELING
When designing new main extensions, computer modeling can help determine the optimum size facilities
for present and future needs. Undersized facilities are costly to replace, and oversized facilities incur
unnecessary expenses to Avista and its customers.
THEORY AND APPLICATION OF STUDY
Natural gas network load studies have evolved in the last decade to become a highly technical and useful
means of analyzing the operation of a distribution system.Using a pipeline fluid flow formula,a specified
parameter of each pipe element can be simultaneously solved. Through years of research,pipeline
equations have been refined to the point where solutions obtained closely represent actual system
behavior.
Avista conducts network load studies using GL Noble Denton's Synergi®4.8.0 software. This computer-
based modeling tool runs on a Windows operating system and allows users to analyze and interpret
solutions graphically.
CREATING A MODEL
To properly study the distribution system,all natural gas main information is entered(length,pipe
roughness and size)into the model. "Main" refers to all pipelines supplying services.
Nodes are placed at all pipe intersections,beginnings and ends of mains,changes in pipe
diameter/material, and to identify all large customers. A model element connects two nodes together.
Therefore, a"to node" and a"from node"will represent an element between those two nodes. Almost all
of the elements in a model are pipes.
Regulators are treated like adjustable valves in which the downstream pressure is set to a known value.
Although specific regulator types can be entered for realistic behavior,the expected flow passing through
the actual regulator is determined and the modeled regulator is forced to accommodate such flows.
FLUID MECHANICS OF THE MODEL
Pipe flow equations are used to determine the relationships between flow,pressure drop, diameter and
pipe length. For all models,the Fundamental Flow equation(FM) is used due to its demonstrated
reliability.
Efficiency factors are used to account for the equivalent resistance of valves, fittings and angle changes
within the distribution system. Starting with a 95 percent factor,the efficiency can be changed to fine tune
the model to match field results.
2025 Natural Gas IRP Appendix 358

Pipe roughness, along with flow conditions,creates a friction factor for all pipes within a system. Thus,
each pipe may have a unique friction factor,minimizing computational errors associated with generalized
friction values.
LOAD DATA
All studies are considered steady state; all natural gas entering the distribution system must equal the
natural gas exiting the distribution system at any given time.
Customer loads are obtained from Avista's customer billing system and converted to an algebraic format
so loads can be generated for various conditions. Customer Management Module(CMM), an add-on
application for Synergi,processes customer usage history and generates a base load(non-temperature
dependent)and heat load(varying with temperature) for each customer.
In the event of a peak day or an extremely cold weather condition, it is assumed that all curtailable loads
are interrupted. Therefore,the models will be conducted with only core loads.
DETERMINING NATURAL GAS CUSTOMERS' MAXIMUM HOURLY USAGE
DETERMINING DESIGN PEAK HOURLY LOAD
The design peak hourly load for a customer is estimated by adding the hourly base load and the hourly
heat load for a design temperature. This estimate reflects highest system hourly demands, as shown in
Table 1:
Table 1 -Determining Peak'Hourly Load
Peak Hourly Base + Peak Hourly _ Peak Hourly
Load Heat Load Load
This method differs from the approach that is used for IRP peak day load planning. The primary reason
for this difference is due to the importance of responding to hourly peaking in the distribution system,
while IRP resource planning focuses on peak day requirements to the city gate.
APPLYING LOADS
Having estimated the peak loads for all customers in a particular service area, the model can be loaded.
The first step is to assign each load to the respective node or element.
GENERATING LOADS
Temperature-based and non-temperature-based loads are established for each node or element,thus loads
can be varied based on any temperature(HDD). Such a tool is necessary to evaluate the difference in flow
and pressure due to different weather conditions.
GEOGRAPHIC INFORMATION SYSTEM (GIS)
Several years ago Avista converted the natural gas facility maps to GIS. While the GIS can provide a
variety of map products,the true power lies in the analytical capabilities. A GIS consists of three
components: spatial operations, data association and map representation.
A GIS allows analysts to conduct spatial operations(relating a feature or facility to another
geographically). A spatial operation is possible if a facility displayed on a map maintains a relationship to
other facilities. Spatial relationships allow analysts to perform a multitude of queries, including:
2025 Natural Gas IRP Appendix 359

❑ Identify electric customers adjacent to natural gas mains who are not currently using natural gas
❑ Display the number of customers assigned to particular pipes in Emergency Operating Procedure zones
(geographical areas defined to aid in the safe isolation in the event of an emergency)
❑ Classify high-pressure pipeline proximity criteria
The second component of the GIS is data association. This allows analysts to model relationships
between facilities displayed on a map to tabular information in a database.Databases store facility
information, such as pipe size,pipe material,pressure rating, or related information(e.g., customer
databases, equipment databases and work management systems). Data association allows interactive
queries within a map-like environment.
Finally,the GIS provides a means to create maps of existing facilities in different scales,projections and
displays. In addition,the results of a comparative or spatial analysis can be presented pictorially. This
allows users to present complex analyses rapidly and in an easy-to-understand method.
BUILDING SYNERGI®MODELS FROM A GIS
The GIS can provide additional benefits through the ease of creation and maintenance of load studies.
Avista can create load studies from the GIS based on tabular data(attributes)installed during the mapping
process.
MAINTENANCE USING A GIS
The GIS helps maintain the existing distribution facility by allowing a design to be initiated on a GIS.
Currently, design jobs for the company's natural gas system are managed through Avista's Maximo tool.
Once jobs are completed,the as-built information is automatically updated on GIS, eliminating the need
to convert physical maps to a GIS at a later date. Because the facility is updated, load studies can remain
current by refreshing the analysis.
DEVELOPING A PRESENT CASE LOAD STUDY
In order for any model to have accuracy,a present case model has to be developed that reflects what the
system was doing when downstream pressures and flows are known. To establish the present case,
pressure recording instruments located throughout the distribution system are used.
These field instruments record pressure and temperature throughout the winter season. Various locations
recording simultaneously are used to validate the model. Customer loads on Synergi®are generated to
correspond with actual temperatures recorded on the instruments. An accurate model's downstream
pressures will match the corresponding field instrument's pressures. Efficiency factors are adjusted to
further refine the model's pressures and better match the actual conditions.
Since telemetry at the gate stations record hourly flow,temperature and pressure,these values are used to
validate the model. All loads are representative of the average daily temperature and are defined as hourly
flows. If the load generating method is truly accurate, all natural gas entering the actual system(physical)
equals total natural gas demand solved by the simulated system(model).
DEVELOPING A PEAK CASE LOAD STUDY
Using the calculated peak loads, a model can be analyzed to identify the behavior during a peak day. The
efficiency factors established in the present case are used throughout subsequent models.
2025 Natural Gas IRP Appendix 360

ANALYZING RESULTS
After a model has been balanced, several features within the Synergiv model are used to interpret results.
Color plots are generated to depict flow direction,pressure, and pipe diameter with specific break points.
Reinforcements can be identified by visual inspection.When user edits are completed and the model is re-
balanced,pressure changes can be visually displayed,helping identify optimum reinforcements.
PLANNING CRITERIA
In most instances,models resulting in node pressures below 15 psig indicate a likelihood of distribution
low pressure, and therefore necessitate reinforcements.For most Avista distribution systems, a minimum
of 15 psig will ensure deliverability as natural gas exits the distribution mains and travels through service
pipelines to a customer's meter. Some Avista distribution areas operate at lower pressures and are
assigned a minimum pressure of 5 psig for model results. Given a lower operating pressure, service
pipelines in such areas are sized accordingly to maintain reliability.
DETERMINING MAXIMUM CAPACITY FOR A SYSTEM
Using a peak day model, loads can be prorated at intervals until area pressures drop to 15 psig. At that
point,the total amount of natural gas entering the system equals the maximum capacity before new
construction is necessary. The difference between natural gas entering the system in this scenario and a
peak day model is the maximum additional capacity that can be added to the system.
Since the approximate natural gas usage for the average customer is known,it can be determined how
many new customers can be added to the distribution system before necessitating system reinforcements.
The above models and procedures are utilized with new construction proposals or pipe reinforcements to
determine the potential increase in capacity.
FIVE-YEAR FORECASTING
The intent of the load study forecasting is to predict the system's behavior and reinforcements necessary
within the next five years. Various Avista personnel provide information to determine where and why
certain areas may experience growth.
By combining information from Avista's demand forecast,IRP planning efforts,regional growth plans
and area developments,proposals for pipeline reinforcements and expansions are evaluated with
Synergio.
2025 Natural Gas IRP Appendix 361

Appendix 10.2
Oregon Public Utility Commission Order No. 16-109 (the Order) included the following
language:
Finally, as part of the IRP-vetting process and subsequent rate proceedings, we expect
that Avista conduct and present comprehensive analyses of its system upgrades. Such
analyses should provide: (1) a comprehensive cost-benefit analysis of whether and when
the investment should be built; (2) evaluation of a range of alternative build dates and
the impact on reliability and customer rates; (3) credible evidence on the likelihood of
disruptions based on historical experience; (4) evidence on the range of possible
reliability incidents; (5) evidence about projected loads and customers in the area; and
(6) adequate consideration of alternatives, including the use of interruptibility or
increased demand-side measures to improve reliability and system resiliency.
In order to address this portion of the Order, Avista has prepared this appendix, which
includes documentation addressing the six points above for each of the natural gas
distribution system enhancements included in the 2021 Natural Gas Integrated Resource
Plan (IRP) for Avista's Oregon service territory. Each of these three enhancement projects
represents a significant,discrete project which is out of the ordinary course of business (that
is to say, different from ongoing capital investment to address Federal or State regulatory
requirements, relocation of pipe or facilities as requested by others, failed pipe or facilities,
etc., all of which occur routinely over time and which are discussed below).
The routine,ongoing capital investments can be loosely classified in the following categories
(which are not mutually exclusive):
• Safety-Ongoing safety related capital investment includes the repair or replacement
of obsolete or failed pipe and facilities. This category includes, but is not necessarily
limited to, investment to address deteriorated or isolated steel pipe, cathodic
protection, and the replacement of pipeline which has been built over, as well as the
remedy of shallow pipe or the repair or replacement of leaking pipe.
• System Maintenance - Ongoing capital investment related to system maintenance
includes replacement of facilities or pipe that has reached the end of their useful
lives, as well as other general investment required to maintain Avista's ability to
reliably serve customers.
• Relocation Requested by Others - Ongoing capital investment related to relocation
requested by others falls primarily into two categories,relocation requested by other
parties which is required under the terms of our franchise agreements (such as
2025 Natural Gas IRP Appendix 362

relocations required to accommodate road or highway construction or relocation),
or relocation requested by customers or others (in which case the customer would
be responsible for the cost of the immediate request, but in which case Avista may
perform additional work, such as the replacement of a steel service with
polyethylene to reduce future maintenance or cathodic protection requirements on
that pipe).
• Mandated System Investment-Ongoing capital investment in this category is driven
by Federal or State regulatory requirements, such as investment that results from
TIMP/DIMP programs, among other programs.
Avista's Aldyl-A replacement program has been addressed in substantial detail in Oregon
Public Utility Commission Docket UG-246,Avista/500-501.
2025 Natural Gas IRP Appendix ,

EEV� w
I
2025 Natural Gas Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Wednesday, February 14, 2024
Virtual Meeting
Topic Time (PTZ) Staff
Introductions 9:00 Tom Pardee
January Peak Event 9:10 Tom Pardee
Work Plan 9:30 Tom Pardee
RNG Acquisition 9:50 Michael Whitby
Break 10:20
Customer Impacts 10:30 Tom Pardee
Modeling Update 11 :00 Michael Brutocao
State Policy Update 11 :30 Tom Pardee
Planned Scenarios 11 :55 Tom Pardee
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 285 938 629 442
Passcode: 8TysAy
Download Teams I Join on the web
Or call in (audio only)
[phone]„325846108# United States, Spokane
Phone Conference ID: 325 846 108#
Find a local number I Reset PIN
Learn More I Meeting options
2025 Natural Gas IRP Appendix 364

Gas market winter update
February 14, 2024

After a mild Nov/Dec, winter finally arrives MLK weekend
Overnight lows 1/12-1/13
• Spokane: -10
• Calgary: -33
• Vancouver: 7
• Seattle: 15
• Portland: 15
• Boise: 10
Maximum Temperature Minimum Temperature
0 10 20 30 40 50 60 70 80 90 too
-
Jan 01 Jan 04 Jan 07 Jan 10 Jan 13 Jan 16 Jan 19 Jan 22 Jan 25 Jan 2F. 3-1
30
20
10
0
10
Temperature s;P,1ax1 Temperature (Avg) Temperature ([Ain)
2025 Natural Gas IRP Appendix MIMI,

LK Weekend
Enbridge 9aY
BC Pipeline an'I°°�`
■ �CO Hub
Me i ne at
Kelr.;;na
• Extremely cold temperatures L buHge
Vanc ouv rr
Nanaimo
region wide. Sumas Hub Kingsgate
Victoria
Northwest Gas Transmission
• Avista LDC sets peak load Seattl 5 Pipeline Northwest
records on consecutive days
Helena
1 /12 (Fri), 1 /13 (Sat). as Storage en
E.ilhnn
portl
• The two main pipeline systems Soo
(GTN , NWP) serving the region
ise Idaho Falls
experienced infrastructure
failures on successive days. Med
Opal Hui
2025 Natural Gas IRP Appendix

GTN - Compressor failure Mesa Crowsnest
Enbri algay
BC Pipe e ii1OC
■ C Hub
• Crowsnest compressor fails morning of 1/12/24.
Lefibudge
• GTN issues Force Ma eure. Posts capacity reduction Nanamotawer - —
J p Y Suma Hub Kingsgate
of 800k dth south of Kingsgate. (25% of GTN capacity) Victoria Northw t Gas Transmission
Pipeline Northwest
• Avista is first LDC offtake customer from GTN south of Seatt, 5
Kingsgate and had higher impacts due to this I Helena
• Pressure on GTN starts to fall early afternoon on 1/12. • as Storage e, Flury;
Portl
• GTN issues request for aid.
Sal
• Avista LDC declares gas EOP and requests that
customers conserve gas. Idaho Falls
• Northwest pipeline reverses flow at Mesa compressor
MEd
to boost pressure on GTN. Opal Hub
• Avista monitors pressure throughout the night. By
late morning on 1/13 pressure was climbing.
• Avista ends gas EOP around noon on 1/13.
2025 Natural Gas IRP Appendix

Gas Supply impact
Enbridge 9arY
BC Pipeline '� °°P"
• At approximately 1 PM on 1/13 operators at JP lost WWI,, vm CO Hub
Keloa M neat
L budge
communication with the facility. Withdrawal flows Vancouver
Nanaimo
dropped from 1 . 1 bcf/d to zero. Pressure in 1-5 corridor Sumas Hub Kingsgate
Victoria Northwest Gas starts to drop. Pipeline P Northwest
mission
Seat S
• NWP activates Northwest Mutual assistance agreement.
Requests regional stakeholder shed non-essential load Helena
� s Storage en
and bring on available supply to preserve pressure. F'
• Around 3 PM, on-site crews manually open valves to
allow free flow of 0.5 bcf/d.
ise ldah�F.dlr
• At approximately 6:30 PM operators regained
communications link to JP. Flows ramped back up to 1 . 1 Med
bcf/d. NWP terminated the NMAA. Opal Hub
Jackson Prairie
2025 Natural Gas IRP Appendix '

Day Ahead Prices
25 25
E 20 20
15 15
0
v
10 10
5 5
her
01-Aug-23 01-Sep-23 01-Oct-23 01-Nov-23 01-Dec-23 01-Jan-24 01-Feb-24
AECO ■ HENRY H U B ■ MALI N ■ ROCKI ES ■ SU MAS
2025 Natural Gas IRP Appendix

• Avista withdraws 1.32 Bcf over 5 days (1/12-1/16)
• JP total withdrawal 4.77 Bcf of 25 Bcf capacity
Avesta JP Storage
Jan Feb Mar Apr May Jun Jul Au Sep Oct Nov Dec
9M _ 9
8M _ 8M
7M _ _ .. 7M
6M _ _ _ _ : 6M
5M _ _ _ 51VI
�o
0 4M _..... ... 41VI
3 M _ 3M
2M
1M _ 1M
2019-2023 Min/Max 2019-2023 Avg ■ 2024 ■ 2023
*Min, Max, and Averages since 2019
2025 Natural Gas IRP Appendix '

100%
80% 77% 79%
87%
60% 66%
Peak Demand 40%
20% JP % of System Retail Load served
0%
N N N N
C C C C
M M M
N M �A
T T T r
Prior
Peak MLK Weekend Peak
370,000
I 365,867
360,000
359,178
350,000 I
334,943
340,000
� , I 331,354
p 330,000
I
320,000
318,387
310,000
I
300,000
I
290,000
N N N N N
N N N N N
N N M M
N r T T r
CV r T T T
T
2025 Natural Gas IRP Appendix

Demand by Area
400.000
00%
■KF °LAG ■MED ROSE ■ID-WA 90%
------------ a
350.000 h 80%
d 70%
300.000
60%
N
250.000 N so°i°
0
w 40%
O
0 200.000 30%
20%
150.000
10%
100.000 0%
1/12/2024 1/13/2024 1/14/2024 1/15/2024 1/16/2024
-a--ID 94% 94% 76% 71% 72%
50.000 tWA 93% 94% 75% 71% 72%
-o--KF 51% 41% 53% 53% 60%
tLaGrande 84% 96% 79% 87% 89%
tMed 54% 52% 44% 54% 69%
1/12/2024 1/13/2024 1/14/2024 1/15/2024 tRose 50% 39% 54% 68% 70%
Total Dth: 359,178 365,867 318,387 331,354
2025 Natural Gas IRP Appendix `

VISTA&
Work P
TAC 1 — 2025 Gas IRP

Schedule and Topics
• TAC 1: Wed. February 14, 2024: 9:00 am to 12:00 pm (PTZ) TAC 4: Wed. 5 June 2024: 10:30 am to 12:00 pm (PTZ)
• January Peak Event Feedback from prior TAC (10 min.)
• Work Plan Future Climate Analysis Update (45 min.)
• RNG Acquisition Historic weather comparison (15 min.)
Customer Impacts Peak Day Methodology (20 min.)
Modeling Update TAC 5: Wed. 26 June 2024: 10:30 am to 12:00 pm (PTZ)
State Policy Update Feedback from prior TAC (10 min.)
Planned Scenarios for Feedback - GHG assumptions and Climate pricing (40 min.)
• TAC 2: Wed. April 24, 2024: 10:30 am to 12:00 pm (PTZ) Current natural gas resources (40 min.)
Feedback from prior TAC (10 min.) TAC 6: Wed. 17 July 2024: 10:30 am to 12:00 pm (PTZ)
Action Items from 2023 IRP (30 min.) Feedback from prior TAC (10 min.)
Chosen Model Methodology and modeling overview (50 min.) Load Forecast—AEG (80 min.)
• TAC 3: Wed. 15 May 2024: 10:30 am to 12:00 pm (PTZ)
Feedback from prior TAC (10 min.)
Distribution System Modeling (45 min.)
Non-Pipe Alternatives (NPA) in Distribution Planning (20 min.)
Oregon Staff Recommendation on NPA(15 min.)
2025 Natural Gas IRP Appendix 375
AM ISM
2

Schedule and Topics
• TAC 7: Wed. 7 Aug. 2024: 10:30 am to 12:00 pm (PTZ) TAC 10: Wed. 6 Nov. 2024: 9:00 am to 12:00 pm (PTZ)
Feedback from prior TAC (10 min.) Scenario Results (30 min.)
Natural Gas Market Overview and Price Forecast (40 min.) Scenario Risks (30 min.)
New Resource Options Costs and Assumptions (40 min.) PRS Overview of selections and risk (30 min.)
• TAC 8: Wed. 28 Aug. 2024: 10:30 am to 12:00 pm (PTZ) Per Customer Costs by Scenario (15 min.)
Feedback from prior TAC (10 min.) Cost per MTCO2e by Scenario (15 min.)
Conservation Potential Assessment (AEG) (30 min.) Open Questions (60 min.)
Demand Response Potential Assessment (AEG) (20 min.)
• Conservation Potential Assessment (ETO) (30 min.)
• TAC 9: Wed. 18 Sep. 2024: 10:30 am to 12:00 pm (PTZ) Sep. 2024 -Virtual Public Meeting- Natural Gas & Electric IRP
• Feedback from prior TAC (10 min.) Recorded presentation
NEI Study (Placeholder if study is conducted) (30 min.) Daytime comment and question session (12pm to 1 pm- PTZ)
Avoided Costs Methodology (20 min.) Evening comment and question session (6pm to 7pm- PTZ)
All assumptions review (30 min.)
2025 Natural Gas IRP Appendix 376
�IIII /ISM
3

Work Plan Summary
• This plan outlines the process Avista will follow to develop its 2025 Gas IRP for filing with the Idaho, Oregon, and Washington
Commissions b April 1, 2U25. Avista uses a transparent public process to solicit technical expertise and stakeholder feedback throughout the
development ofythe IRP through a series of Technical Advisory Committee (TAC) meetings and public outreach to ensure its planning process
considers input from all interested parties prior, w
to Avista's decisions on how to meet future customer gas needs. Avista posts all meetinggs
announcements, meeting minutes, videos, final IRP documents and data on its website at htt s://ww.m avista.com/about-us/inte rated-
resource- lannin Avista will communicate with its TAC members through email and MicrosoYfeams tor any meeting n- ormation and data
sharing outside of TAC meetings. Avista will provide all information related to TAC meeting content prior to, or shortly after each TAC
meeting if any updates to presentations or data have been made. Final data and documents will be made available upon filing of the iRP.
• The 2025 IRP process will explore the use of new modeling techniques. The models under consideration include PLEXOS, as used in the
2023 IRP, but it is also considering internally developed tools are under exploration. Costs of models have been steadily increasing and have
created an opportunity to evaluate alternative modeling options to help contain costs to customers while providing the same level of analysis
and considerations necessary in an IRP. Avista may use Avista's Electric IRP's PRISM for certain resource selection options but intends to
investigate alternative options to PLEXOS for the ability to provide this functionality in a timely manner for all jurisdictions. Avista will share
outcomes of modeling comparisons prior to a decision to move toward a selected model.
• Avista contracted with Applied Energy Group (AEG) to assist with key activities including the energy efficiency and demand response
potential studies. AEG will also provide the IRP with a long-term energy forecast using end use techniques to improve estimates for building
and transportation electrification scenarios. Avista also intends to align the IRP's load forecast and resource options with this study. The Energy
Trust of Oregon (ETO) will continue to provide results for the Avista Oregon territories and will be directly input into the model as a cost and
load savings.
• Avista intends to use both detailed site-specific and generic resource assumptions in the development of the 2025 IRP. The assumptions will
utilize Avista's research of similar gas producing technologies, engineering studies, vendor estimates and market studies. Avista will rely on
publicly available data to the maximum extent possible and provide its cost and operating characteristic assumptions and model for review and
input by stakeholders. The IRP may model certain resources as Purchase Agreements rather than Company ownership if third party ownership
is likely to be lower cost. Future Requests for Proposals (RFP) will ultimately decide final resource selection and ownership type based on third
party resource options and potential self-build resources specific to Avista's service territory.
2025 Natural Gas IRP Appendix 377
4
'eIIII ormsra®

Work Plan Summary (cont.)
• Avista intends to create a Preferred Resource Strategy (PRS) using market and policy assumptions based on final rules from
the Climate Commitment Act (CCA) for Washington. In Oregon the Climate Protection Plan (CPP) will be included as a scenario as
the Department of Environmental Quality moves to re-establish the program in 2024. Conversations with the TAC as to methods
and logic to include in scenarios will be discussed including beginning the program in 2025 for the PRS. Final CPP rules, that may
be the same, will not be known until after the modeling and process of the 2025 IRP is completed. A similar outcome is possible
with the Climate Commitment Act (CCA). A public initiative providing sufficient signatures was submitted to the Legislature where it
can be repealed, altered or voted on in the November 2024 election. A further outcome includes the possibility of joining the
California cap and trade program. This will also alter program rules of the CCA to conform to the California cap and trade program
rules more closely. Finally, a least cost planning methodology will be used in Idaho. For Washington resource selection, Avista will
solve its PRS to include least reasonable cost for meeting state energy policies including energy costs, societal externalities such
as Social Cost of Greenhouse Gas , and the non-energy impacts of resource on public health (air emissions), safety, and
economic development . Resource selection will solve for state clean energy requirements and Avista's energy and capacity
planning standards. Avista will track certain customer metrics the PRS creates to assist in measuring customer equity.
• The plan will also include a chapter outlining the key components of the PRS with a description of which state policy is driving
each resource need. The IRP will include a limited number of scenarios to address alternative futures in the gas market and public
policy, such as limited RNG and building electrification. TAC meetings help determine the underlying assumptions used in the IRP
including market scenarios and portfolio studies. Although, Avista will also engage customers using a public outreach and an
informational event as well as provide transparent information on the IRP website. The IRP process is technical and data intensive;
public comments are encouraged as timely input and participation ensures inclusion in the process resulting in a resource plan
submitted according to the proposed schedule in this Work Plan to meet regulatory deadlines. Avista will make all data available to
the public except where it contains market intelligence or proprietary information. The planned schedule for this data is shown in
Exhibit 1 . Avista intends to release slides and data five days prior to its discussion at Technical Advisory Committee meetings and
expects any comments within two weeks after the meeting.
2025 Natural Gas IRP Appendix 378
III/V�sTa
5

Sections in IRP
5. Policy Issues
1. Introduction and Planning Environment a Avista's Environmental Objective 8. Distribution Planning
a. Customers b Natural Gas Greenhouse Gas System Emissions Distribution System Planning
b. Integrated Resource Planning c. Local Distribution Pipeline Emissions - Methane Study Network Design Fundamentals
C. Planning Model d State and Regional Level Policy Considerations Computer Modeling
ri Planning Environment a Idaho Determining Peak Demand
2. Demand Forecasts f. Oregon Distribution System Enhancements
a. Demand Areas g Washington Conservation Resources
b. Customer Forecasts h Federal Legislation Distribution Scenario Decision-Making
c. Electrification of Natural Gas Customers i Customer Market study Process
d. Use-per-Customer Forecast Key Takeaways Planning Results
e. Weather Forecast 6. Preferred Resource Strategy Non-Pipe Alternatives
f. Peak Day Design Temperature _ Planning Model Overview 9. Equity Considerations
g. Load Forecast b Stochastic Analysis Overview
h. Scenario Analysis c. Resource Integration Equity Metrics
i Alternative Forecasting Methodologies d Carbon Policy Resource Utilization Summary 10. Action Plan
Key Issues e. Resource Utilization Avista's 2025 IRP Action Items
3. Demand Side Resources f. Demand and Deliverability Balance 2025-2026 Action Plan
a. Avoided Cost g. New Resource Options and Considerations
b. Idaho and Washington Conservation Potential Assessment h Energy Efficiency Resources
c. Pursuing Cost-Effective Energy Efficiency i. Preferred Resource Strategy(PRS)
d. Washington and Idaho Energy Efficiency Potential j. Monte Carlo Risk Analysis
e. Demand Response L Estimated Price Impacts
f. Building Electrification 7. Alternate Scenarios
4. Current Resources and New Resource Options a Alternate Demand Scenarios
3. Natural Gas Commodity Resources b Deterministic—Portfolio Evaluation and Scenario Results
b. Transportation Resources c. Demand
c. Storage Resources d PRS Scenarios
d. Incremental Supply-Side Resource Options e Electrification Scenarios
e. Alternative Fuel Supply Options f. Supply Scenarios
f. Project Evaluation - Build or Buy g. Other Scenarios
g. Avista's Natural Gas Procurement Plan h Washington Climate Commitment Act Allowances
h. Market-Related Risks and Risk Management i. Oregon Community Climate Investments
j. Natural Gas Use
k. Synthetic Methane
I. Renewable Natural Gas
m. Emist,� natural Gas IRP Appendix 379
n. Cost�omparison AIIW_
6 o- Regulatory Requirements �IiiVISTAW

Major Timeline
Exhibit 1 : Major 2025 Gas IRP Assumption Timeline
Task Target Date
Market Price Assumptions August 2024
CCA/Other GHG Pricing Assumptions June 2024
Natural Gas price forecast Au ust 2024
New Resource Options Cost & Availability August 2024
AEG Deliverables August 2024
Final Energy Forecast
Energy Efficiency and Demand Response Potential Assessment
Due date for study requests from TAC members July 30, 2024
Determine portfolio & market future studies July 2024
Finalize resource selection model assumptions September 2024
2025 Natural Gas IRP Appendix 380
�IIII��STa®
7

Next Steps
• Feedback from TAC of areas missing or additional topics
needed to add to the workplan
Please submit areas of concern by March 15t", 2024
• File Plan by April 1 , 2024
2025 Natural Gas IRP Appendix 381
III/V�STa
8

'All
Renewable Natural Gas Acquisition
TAC 1 — 2025 Gas IRP
February 14, 2024 INV=W -M

RNG is a drop-in replacement for Natural Gas
Keep the pipes Charixe the fuel
Procurement Process Regardless of procurement strate
Customer Use L.Drimary • - • • • "
A&MMI
Buy:
• Avista has commenced an annual RFP
cycle to test the market for least cost RNG
project investments and RNG offtake
-� opportunities
Clean Up
CO2 & Methane Build:
Collected Avista has considered developing RNG
capital investment projects as self-build
_ projects at a feedstock host sites
w
Landfills
Farms
2025 Natural Gas IRP Appendix
2

Procurement = Build
• Avista has considered developing RNG projects under Oregon SB 98 and Washington HB 1257.
Through this effort Avista has developed an understanding of the costs and risks associated
RNG development. Some observations and challenges include:
• Cost varies by feedstock type and distance to interconnection point.
• Utilities desiring to develop RNG projects are fully dependent on a feedstock host site with an
owner that is willing to collaborate and cooperate and be patient with the development lead times &
the regulatory process.
• The regulatory process, timing, and uncertainty of cost recovery is undesirable as compared to
"buy" alternatives.
• Private developers are nimble, may build at a lower cost and can access all markets.
• Higher risk profile
2025 Natural Gas IRP Appendix
3

Procurement = BiIIIIIII& M
• Avista has commenced an annual RFP process in 2022 seeking:
• Bundled or unbundled RNG RTC supply
• RNG Projects — Investment/partnering opportunities (Build)
• Long Term (15 year) RNG Offtake opportunities (Buy)
• Some observations from the RFP process:
• RNG Developers are offering lower coast as compared to Marketers/Brokers
• Nearly all RFP proposals have been for unbundled RNG environmental attributes only
proposals.
• Projects are distributed across North America with only two in the PNW.
• RNG developers are nimble, may build at a lower cost and can access all markets.
• Lower risk profile
2025 Natural Gas IRP Appendix
4

2022 Request for Proposals for Renewable Natural Gas
15 Respondents
47 Projects 2022 Renewable Natural Gas Request for Proposals
eplalry on w.aspkxlanal gaah fo rmpre Nlpra gaa emiaaipna wx M mw ana m m rxbon reuval m oxr
alga operations fry NMS.aM meet Oregon's Climate I--Program aM WasningtanSfllmate
CommnmenI An carbon re0un1-
• requlrenpnti,gvNG bat relexe0 a reguM for popouh leaking renewable
7 8 — 9.5 M RTCs afuolgxlRNGE WwYingxAYlsu
Rtie RiPbopen 1p pane.wnp fpnenuv AYISIWaY�e�gulremenh pim RN4.aaaenrmav Rrane,rl„u��rxelkga
xuor pwtiono or reaunx maenng pk walanaah: kwegrateO Reaaure PbllWV
ploposal mry In<IuOe renain mnfguratlo2<ontMMg or gkinq apllol¢Atirta antiupatx RN4 Oeliverla fo
be no earlier than January I.lOIg. •gOlg All Sauna R{P
Do[IYllknb •M32 RelleaYable llaUq fixM
y •pv�sta RNG cuyvsljg@ppgylyjq}j •gisVlOullon Plmning AOvlwry Group
X •flB e mce a mvrer Wxxhglon'r Clean FnergY future
•gipOetiCm
$25.00
$20.00
$15.00
—Cost Curve
^L`
CL
$10.00
$5.00
r- O N M ti O O 7 N "': O o0 Iq O M r, CO M
N N N N N N M CO CO CO 'tt 1:1- LO LO In V) r- r- W M M M
Millions of RTCs
2025 Natural Gas IRP Appendix
5

2023 Request for Proposals for Renewable Natural Gas
IF
12 Respondents ,.0........tI.,_
2023 RNG/RSG Request for Proposals
22 + Projects
Building on our asplrationaI goals to reduce natural gas emissions 30%by 2030 and to be carbon neutral in our
natural gas operations by 204S,and to meet Oregon's Climate Protection Program and Washington's Climate
Commitment Act carton reduction requlrements,Avista has released a request for proposals seeking renewable
10 M RTC s — RNG natural gas(RING)/Responsibly Sourced Gas(RSG).
resource Cels open to parties who currently own,propose to develop,or hold rights d resources,or those marketing a
/\ or portfolio of resources meeting Avista's requirements for RNG/RSG.Bitlders may submit multiple
proposals;each proposal may Include certain config uratlon,contracting or pricing options.Avista anticipates
RNG/RSG deliveries to be no earlier than January 1,2024.
14 M RTC s — A l t Fuels Documents
•Av sta RNG RNust for Proposals 2023
Exhibit A
•RNG&RSG Repuest for Prorlosalt Bidders Conference Presentation
•RNG/RSG Vendor Temgfate
•RNG RFP Bidders Conference Ouesl'ons and Answers
$80.00
—Cost Curve
$70.00
$60.00
U $50.00
$40.00
a
$30.00
$20.00
$10.00
Ln O O N N N 00 Ln co O M rl- it 1:1- I:t Cfl M Ln rI_ rl- Ln Ln
qit r,- O r O) 00 — LO r'- 00 Cfl r,- 00 M CD 00 O N Co CO 00 Cfl
O O — r = M qt qt � � CO CO co ti � � 00 00 00 co 00 �
2025 Natural Gas IRP Appendix Volume of RTCs
El (millions) dim

2022=2023 Offtake Contracts for RNG
Avista has executed four RNG contracts with Pine Creek Renewable Natural
Gas
Horn Rapids Landfill RNG - Richland, Washington
■ 15 Year off-take contract
■ Deliveries expected Q1 2024
Black Hawk County Landfill RNG - Waterloo, Iowa
■ 15 Year off-take contract
■ Deliveries expected Q4 2024 ` n
Bayview Landfill RNG — Elberta, Utah Qj*sCIR
■ 15 Year off-take contract
■ Deliveries expected Q1 2024
Quad Cities Landfill Facility RNG - Milan, Illinois •� -=' - - -..
■ 15 Year off-take contract
■ Deliveries expected Q4 2024
2025 Natural Gas IRP Appendix
7

Pine Creek RNG Offtake Supply Contracts
1,400,000
LandfillBayview • Landfill MMBtu/Year
QuadLandfill
11 111 • ' , • • •
.• 1,000,000
800,000
0 600,000
400,000
200,000
2023 20241 1 • 2027 202819 2030 2031 20321 134 2035 2036 2037
RN Offtake Contract & Market Structure
— Contract Duration: 15 Years commencing in 2024 - 2025
— Contracts represent 50% & 100% of RNG Project Volumes:
— Environmental Attributes only (unbundled) purchased as Renewable Thermal Certificates
(RTC)
— Attribute Tracking: tracked in M-RETS
Developer RNG produce:. or rn;ntsn 1 s� !s Environmental Attributes as RTC's and RIN's r ✓ISTA'

RNG Offtake Market Structure
Volume of RIN's pointed to Transportation Market (EPA RSF) (% Flexible):
1 . RIN's produce revenue
2. RNG developer administers RIN transactions and shares % of RIN revenue with Avista
3. RIN revenues subsidize Avista net RNG cost (RNG cap price - RIN Revenue = subsidized RNG cost)
4. Through this structure Avista customers enjoy RNG at below RNG market cost
5. The higher the value of the RIN the more Revenue
100% OF VOLUME 50% OF VOLUME 0 % PROJECT VOLUME
SOLD TO RIN MARKET SOLD TO RIN MARKET SOLD TO RIN MARKET
RFP $ AVG.
RNG + $ RNG $$ RNG $$$$
MARKET LEVERAGE FLEXIBILITY
2025 Natural Gas IRP Appendix
9

�iivlSTA'
Customer Impacts
TAC 1 — 2025 Gas I RP

Customer Impact Considerations
Possible methods to add equity into the 2025 Gas IRP:
1 ) Add an Equity Chapter
2) Include metric results in the IRP Equity chapter and others, including:
- GHG emissions
- Rates
- Energy Burden
- Potential for other air emissions
3) Map out Avista "named communities"
4) Distribution equity: Non-Pipe Alternatives (NPA) for any distribution
upgrade
This topic will be discussed in detail in TAC 2 with distribution planning
5) NEI Study?
2025 Natural Gas IRP Appendix 392
�IIII��STa®
2

Energy Justice Core Tenets with IRPs
• Recognition : • Distribution :
Identify Named Communities Performance measures
Quantify Energy Burden Account for Non-Energy Impacts
• Procedural : • Restorative:
Open Technical Advisory Energy Efficiency Programs
Committee Meetings Non-Pipe Alternative
• On-line Customer Oriented Distribution Planning
Planning Sessions
2025 Natural Gas IRP Appendix 393
3
'eIIII Irmsra®

NEI Study Request Overview
Avista is seeking assistance to identify societal non energy impacts (NEI )
for resource decisions in the natural gas distribution business. As Avista and
other regional utilities will be seeking alternative natural gas fuel supplies
over the coming decades to comply with state clean energy policies. Avista
seeks to understand costs and benefits to resource decisions going beyond
reduction in greenhouse gas emissions.
Avista seeks to understand NEI's for the following resource alternatives:
• Renewable Natural Gas
• Hydrogen & Synthetic Methane
• Natural Gas
2025 Natural Gas IRP Appendix 394
4 e1111 or sma®

Study Overview
Area of Study Generalized Approach
Public Health Air emissions contributed due to consumption of hydrocarbons consumed during the
production of the fuel. Such as PM2.5, S02, NOX, and GHG. Also include difference
in methane or other GHG as compared to traditional natural gas.
Safety Fatalities and injuries resulting from operations of production
Land Use Consider the footprint of facilities that are above and beyond the standard
calculations considered as part of alternative facility construction for the required
energy. Displacement of land that was beyond the facility's footprint may also be
considered.
Water Use Identify water usage and impact of usage on process with return of a product back to
a clean product i.e. fracking water not always useful after usage)
Economic Induced economic impact to the facilities construction and operation, including job
growth.
Community Odor Pollution Aromatic quality of the air in the community including mercaptan and organic
decomposition. This should also consider the air quality of processes to create fuels.
Process Bi-products Value in the creation of biproducts such as carbon black, biochar, fertilizers, carbon
fiber, or graphite.
Local Distribution Pipeline Impacts related increase or decrease in requirement to the Local Distribution
Company LDC pipeline network, includes qualify of gas and volume impacts
2025 Natural Gas IRP Appendix 395
5
eilVISTA

Study Summary
• For each fuel type discussed below a cost estimate in a US $ per
dekatherm equivalent for each NEI is required
• If the NEI impact is related to construction , these benefits may be
levelized over the life of the project when calculating the $ per dekatherm
equivalent.
• For processes requiring electricity for production , NEI's for the electric
demand is not required , but the electric consumption shall be provided
(i .e. kWh per mmBTU).
2025 Natural Gas IRP Appendix 396
�IIIIV�STa®
6

�iivlSTA�
Modeling Update
TAC 1 — 2025 Gas IRP

Timeline : IRP Modeling Software
Prior to 2023 2023 IRP 2025 IRP
PLE S
BY ENERGY E%EMPLAR
■
SENDOUT® PLEXOS®
2025 Natural Gas IRP Appendix 398
�IIIIV�STa®
2

Potential 2025 IRP Modeling Software
SENDOUTO
• "SENDOUT is used by energy companies as the foundation for gas supply planning and asset valuation
analytical processes. Hitachi Energy gas analytics solution set incorporates scenario and stochastic analysis
and simulates forward curves and related trading behavior. The software suite provides an assessment of gas
portfolio costs, reliability, risks, and opportunities, revealing the impact of potential operating, weather, and
price conditions."
PLEXOS°
• "PLEXOSO is a powerful simulation engine that provides analytics and decision-support to modellers, generators,
P L E S and market analysts—offering flexible and precise simulations across electric, water, gas and renewable energy
markets." [2]
Avista CROM E - What'sBest! O
"What'sBest! is an add-in to Excel that allows you to build large scale optimization models in a free form layout
within a spreadsheet. What'sBest! combines the proven power of Linear, Nonlinear (convex and
nonconvex/Global), Quadratic, Quadratically Constrained, Second Order Cone, Semi-Definite,
Stochastic, and Integer optimization with Microsoft Excel -- the most popular and flexible business modeling
environment in use today." [31 Avista would use this software functionality to build and solve CROME
(Comprehensive Resource Optimization Model in Excel)
[1] https://www.hitachienergy.com/products-and-solutions/energy-pgglgAg�[Uffipgpga gnteri)rise/sendout 399
0 0 0 I
[2] https://www.energ /`20-0/`2OBrochure/`20-/`2OA4.pdf �/Iu�IIrmsma
3 [3] https://www.lindo.com/index.php/products/what-sbest-and-excel-optimization

Selection Criterion
TRANSPARENCY FLEXIBILITY
2025 Natural Gas IRP Appendix 400
�IIII��STa®
4

TRANSPARENCY
TRANSPARENCY
�r
PLE S
BV ENERGY EXEMPLAR
Avista CROME - What'sBest!® PLEXOS® SENDOUT®
• Modeled in Microsoft Excel Increasingly common Updates are no longer
• Accessible platform used by software among gas and available
large and diverse population electric utilities
• Inputs, assumptions,
• LDC use throughout the
constraints, logic, and results
• Requires license to view, northwest is decreasing
are accessible without solve, and read
• Requires license to view,
license documentation
solve, and read
• Requires license to solve documentation
• Documentation not complete
2025 Natural Gas IRP Appendix 401
�IIIIV�STa
5

TRANSPARENCY FLEXIBILITY
FLEXIB11 " '
PLE S
BV ENERGY EXEMPLAR
11111-���
Avista CROME - What'sBest!® PLEXOS® SENDOUT®
• Ability to model new • Receives regular updates • Not easily flexible to include
concepts is not constrained • Workarounds available to climate programs and
• Data files are limited to size model unique scenarios and emission factors
of spreadsheet resources
• Instant output of model • Large database files • Large database files
results in required usable produced produced
format • Data needs manipulation to . Data needs manipulation to
• Understanding of understand and provide in understand and provide in
calculations and methods usable format usable format
used within the program
2025 Natural Gas IRP Appendix 402
�IIII��STa®
6

TRANSPARENCY FLEXIBILITY
SPEEDSPEED
PLE S
BV ENERGY EXEMPLAR
Avista CROME - What'sBest!® PLEXOS® SENDOUT®
• Initial testing indicates • Sufficient speed to meet • Sufficient speed to meet IRP
sufficient speed to meet IRP 2023 IRP deadlines deadlines prior to 2023
deadlines
• Ability to run on multiple • Ability to run on multiple
• Ability to run multiple computers with upgrade to computers
instances per license base modeling software
• Has not been tested with
• Cloud-based service new policies (CCA, CPP)
available and unique resources
2025 Natural Gas IRP Appendix 403
III/ riST'a
7

TRANSPARENCY FLEXIBILITY
COST COST
PLE S
6 BV ENERGY EXEMPLAR
Avista CROME - What'sBest!® PLEXOS® SENDOUT®
• Software is purchased and • Annual subscription-based • Software is purchased and
only cost would be to add software no additional costs
licenses as needed
• Relatively expensive • Time to familiarize new and
• Relatively inexpensive when infrequent users to software
compared to alternatives Time to familiarize new and and modeling interface
infrequent users to software
• Likely least cost option when and modeling interface
considering software
upgrades
2025 Natural Gas IRP Appendix 404
8 *Additional computer hardware, training and computer costs are not included �iIVISTA®

Timeline : IRP Modeling Software 2025 IRP
Prior to 2023 2023 IRP
PLE S
BY ENERGY EXEMPLAR
PLE 6S 2025 IRP
BY ENERGY EXEMPLAR
SENDOUT® PLEXOS®*
Other
* 2025 Natural Gas IRP Appendix /■ 405
9 Need to decide on extending contract in late March 2024 �Ii�/ISTA®

Initial Deterministic Model Comparison
Natural Gas Renewables*
LA 50 N 18,000
E E 16,000
40 14,000
° f0 12,000
30 p 10,000
0 20 8,000
6,000
10 o 4,000
t
2,000
M ':I* In l0 r` W M O -1 N M � Ln l0 n W M O ci N M V Ln M -It Ln l0 r` W M O � N m � Ln l0 r` W M O 1-1 N M -It Ln
N N N N N N N M M M M M M M M M M V a a � N N N N N N N M M M M M M M M M M � � � � a a
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N . N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
■ PRS-2023 IRP Avista CROME ■ PRS-2023 IRP Avista CROME
Compliance Mechanisms** Annual System Costs
1,400 $700
p 1,200 0 $600
U
~ 000,1� � 2 $500
_0 800 $400
v) 600 $300
400 $200
200 $100
m V1 l0 r� w m O m -zd, Ln l0 r\ w Q1 O 1-1 N m z3- Ln m -:t Ln l0 r\ w m O m -;t Ln l0 r` w m O r-i N m zt In
N N N N N N N m M M M m m M M M m :T IZT Izi- -Zl- RZT N N N N N N N m m M M M M m M M M zT -Zd- Izi- IZT 'T
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N . N N N N N N N N . N N N N N N . N N N N N N N N N N . N N N N N N N N N
■ PRS-2023 IRP Avista CROME ■ PRS-2023 IRP Avista CROME
* 2025 Natural Gas IRP Appendix 406
Includes RNG, H2, and Synthetic Methane 10 ** Includes Allowances and CCIs �u1-1nsra

Next Steps
• Continue validating CROME built with What's Best
• Chosen model methodology update - TAC 2
- - 2007
0
o �
� �
.Q o
� E
C O
P E S u�i U 0 Selected
Model
c� U)
ull
TAC 1 TAC 2
ism 0 Models used in prior Gas IRPs 2025 Gas IRP Model
2025 Natural Gas IRP Appendix 407
,eIIII Irmsra®

�ai'ISTA°
State Policy Update
TAC 1 — 2025 Gas IRP

Building Codes in Washington
• In November 2023, the building code updates were voted into code by the
SBCC
Under the new rules, a builder will need five credits for a home of less than 1 ,500
square feet. That's double the prior requirement. For a home between 1 ,500 and
5,000 square feet, they will need eight credits, up from five
More credits are given for the use of an electric heat pump than a natural gas furnace
These codes are effective March 15, 2024
The standard reference design shall be a heat pump water heater meeting efficiency
standards of Table C404.2 of chapter 51 -11C WAC
2025 Natural Gas IRP Appendix 409
2 CR102 WSEC R EPCA complete 101823.pdf (wa.gov)
III/vIFsra

Space Heat Source Credits
TABLE R406.2
( ( ) ) ENERGY EQUALIZATION CREDITS
Credits
System Group
Type Description of Heating Sources All Other R-20
1 For combustion heating system using equipment meeting minimum federal ((-3-0))Q 0
efficiency standards for the equipment listed in Table C403.3.2(5)or C403.3.2(6)
2 For an initial heating system using a heat pump that meets federal standards for ((A)) 1_5 0
the equipment listed in Table C403.3.2(2)and supplemental heating provided by
electric resistance or a combustion furnace meeting minimum standards listed in
Table C403.3.2(5)b
3 For heating system based on electric resistance only(either forced air or zonal) ((4.0))0_5 0.S
Credits
System Group
Type Description of Heating Sources All Other R-22
4e For a heating system using a heat pump that meets foderal standards for the 044))3_0 2.0
equipment listed in Table C403.3.2(2)or C403.3.2(9)
or
Air to water heat pump units that arc configured to provide Noth heating and
cooling and arc rated in accordance with AHRI 5501590
5 For heating system based on electric resistance with: ((04))2.0 0
1.Inverter-driven ductless mini-split heat pump system installed in the
largest zone in the dwelling
or
2.With 2 kW or less total installed heating capacity per dwelling
a See Section R401.1 and residential building in Section R202 for Group R-2 scope.
b The gas back-up furnace will operate as fan-only when the heat pump is operating.The heat pump shall operate at all temperatures above 39'F
(3�.3 C)(lolowegr).Belowthat I"changeover"temperature.the heat pump would not operate to provide space heating.The gas furnace provides
c Additional points for this HVAC system arc included in Table R406.3.
2025 Natural Gas IRP Appendix 410
3 Source: CR102 WSEC R EPCA complete 101823.gdf(wa.aov)
AIMMSTA®

CCA
• In November 2023, signatures were delivered under initiative 2117 to repeal
legislation establishing the cap and invest program
Possible Outcomes of CCA Potential Benefits Potential Drawbacks
Certainty of outcome without legal delay Uncertainty of future climate program or
Legislature votes to repeal or ballot initiative to voters what to do with funds from auctions
-May not fix all program issues leading to
Draft and pass an alternative Gives the legislature a chance to fix risk in program
initiative program elements -Subject to voter approval alongside original
version of I-2117
-Create a more robust marketplace for -More entities in the pool for allowances or
allowances, same trading system offsets, new
Link to California (potential cost/credit) -Compliance period moves to every 3 years
-Washington would recognize projects
located in the other jurisdictions
Refuses to Act People will decide in November 2024 Create uncertainties if program is repealed
election
Voters Repeal Certainty of outcome without legal delay Uncertainty of future climate program or
what to do with funds from auctions
2025 Natural IRP Appendix 411
4

CPP
• On December 20, 2023 it was ruled the DEQ did not fully comply with
notice requirements during the rulemaking process for the program ,
thereby invalidating the final rules and the program
• On January 22, 2024 the DEQ moves to re-establish the CPP
Process takes about 12 months (including public comment period)
DEQ will propose the rules for adoption to the Environmental Quality Commission
(governing body)
• The rules could change during the rulemaking process, including having new
elements or shifting timelines per the DEQ
2025 Natural Gas IRP Appendix 412
5
'eIIII grass®

Next Steps
• Work with the TAC to develop scenarios to consider risks involved in
different pathways for state policy and the various potential outcome
• Determine a base case for state policy for use in the Preferred Resource
Selection (PRS) scenario
2025 Natural Gas IRP Appendix 413
�IIII��STa®
6

�� i'ISTA°
Planned Scenarios
TAC 1 — 2025 Gas IRP

Scenarios
Preferred Resource Case Our expected case based on assumptions and costs with a least risk and least cost resource selection. This
scenario includes all known policies and orders from Idaho, Oregon and Washington
Preferred Resource Case (Low/High) Prices Same as PRS, but includes a scenario with a low-price curve for natural gas and a scenario with a high price curve for
natural gas
Preferred Resource Case CCA Ceiling Prices PRS assumptions with a high cost for allowances
Preferred Resource Case with CPP PRS assumptions, but includes the CPP expectations going forward from 2025
Electrification (low,expected,high) conversion A low case to show the risk involved with energy delivered through the natural gas infrastructure moving to the electric
costs system with different levels of conversion costs
Hybrid Heating Case A scenario to include hybrid heating for temperatures below 40 degrees Fahrenheit
High Customer Case A high case to measure risk of additional customer and meeting our emissions and energy obligations
Limited RNG Availability A scenario to show costs and supply options if RNG availability is smaller than expected
High RNG Costs A scenario to measure resource selection with a higher-than-expected set of RNG costs by source
Interrupted Supply A scenario to show the impacts and risks associated with large scale supply impacts and the ability for Avista to provide
the needed energy to our customers
Carbon Intensity Include carbon intensity of all resources from Preferred Resource Case including upstream emissions on natural gas
Natural Gas Only A case to help compare costs of resource decisions from climate policy. This case assumes no alternative fuels or
climate policy with natural gas, energy efficiency and demand response as the expected future resource options
Social Cost of Carbon A scenario to value resources in all locations using the Social Cost of Carbon @ 2.5% and includes upstream
emissions
Average Case Non climate change projected 20-year history of average daily weather and excludes peak day
2
�uVISTA®

2025 Natural Gas Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Wednesday, April 24, 2024
Virtual Meeting
Topic Time (PTZ) Staff
Agenda/Meeting Guidelines 10:30 Tom Pardee
Action Items 10:40 Tom Pardee
Modeling/Assumptions Overview 11 :00 Tom Pardee
CROME High Level Overview 11 :25 Michael Brutocao
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 285 938 629 442
Passcode: 8TysAy
Download Teams I Join on the web
Or call in (audio only)
[phone]„325846108# United States, Spokane
Phone Conference ID: 325 846 108#
Find a local number I Reset PIN
Learn More I Meeting options
2025 Natural Gas IRP Appendix 416

�� i'ISTA°
2023 Gas IRP Action Items

Summary of Acknowledgement
• Idaho — Acknowledged (November 1 , 2023)
• Oregon — Pending short term acknowledgment
• Washington — No word on acknowledgment
2025 Natural Gas IRP Appendix 418
2
'eIIII srasra®

Avista - 2023 Gas IRP Actions
1. 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.
2. New program offered by ETO for interruptible customers in 2023 to save 15,000 therms.
3. Engage Oregon stakeholders to explore additional new offerings for interruptible and low-income customers to work towards identified savings of 375,000 therms in 2024.
4. 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.
5. Begin to offer a Washington transport customer EE program by 2024 with the goal of saving 35,000 therms
6. Explore methods for using Non-Energy Impact(NEI) values in future IRP analysis to account for social costs in Washington to ensure equitable outcomes.
7. Explore using end use modeling techniques for forecasting customer demand.
8. 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.
9. Regarding high pressure distribution or city gate station capital work, Avista does not expect any supply side or distribution resource additions to be needed in our Oregon territory
for the next four years, based on current projections. However, should conditions warrant that capital work is needed on a high-pressure distribution line or city gate station in order
to deliver safe and reliable services to our customers, the Company is not precluded from doing such work. Examples of these necessary capital investments include the following:
Natural gas infrastructure investment not included as discrete projects in IRP
Consistent with the preceding update,these could include system investment to respond to mandates,safety needs, and/or maintenance of system associated with reliability
Including, but not limited to Aldyl A replacement,capacity reinforcements,cathodic protection, isolated steel replacement,etc.
Anticipated PHMSA guidance or rules related to 49 CFR Part§192 that will likely 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
2025 Natural Gas IRP Appendix 419
III/V�STa
3

IPUC = Recommendations
2025 IRP
Recommendation
1 Staff recommends the Company's 2023 Natural Gas IRP be acknowledged and accepted for filing contingent on the Company
submitting a compliance filing with an updated DSM Avoided Cost table that does not include a National Carbon Tax starting in
2030; and
2 Staff recommends that the Commission require the Company to include updates on PLEXOS® implementation, model validation,
and enhancements in its semi-annual Natural Gas Updates with the Commission.
2025 Natural Gas IRP Appendix 420
4
III/vnsra

OPUC = Recommendations
2025 IRP
Recommendation
1 Do not acknowledge 8.64 million therms of RNG in 2023. Removed
For the IRP Update the Company should update the load forecast with a downscaling methodology using
2 Multivariate Adaptive Constructed Analogs as employed by Oregon State University's Institute of Natural
Resources.
Regardless of the analytical approach taken to create the PRS, future IRPs should include alternative resource
3 portfolios that represent different utility decisions.
Future IRPs should include stress testing of the RIPS and alternative resource portfolios and provide metrics
4 comparing the severity and variability of risk in alternative portfolios.
In the next IRP should include modeling of all relevant distribution system costs and capacity costs, including
5 additional projects that would be needed in high load scenarios as well as costs that would not be incurred in
lower load scenarios.
Avista work with the TAC to develop additional scenarios and sensitivities for the next IRP, including for example:
6 greater price variation for low carbon resources, high cost for low carbon resources, omission of any highly
uncertain resource, or utilization of only existing resources.
To start to understand baseline electrification occurring naturally, Staff recommends Avista use advanced
metering infrastructure data and Form 10Q data to capture customer behavior as discussed in Section 6.3. At the
7 IRP update, Avista should present that information in the attached worksheet templates (Attachment B).
In the IRP update, Avista should clarify whether it has precedent agreements or other contracts for the GTN No Agreements with
8 Xpress. If so, Avista should explain its capacity on this 2025 new real xpanas sion. GTN Xpres a2,
5 Dui VISTA

OPUC Staff = Expectations
2025 IRP
Expectation
At a TAC meeting for the next IRP, Avista should provide an estimate of the capacity in MW of electrolyzers, renewable generation, and
1 methanation equipment needed in each year to include synthetic methane in the Oregon PRS. The Company should also provide the cost
and quantity of CO2 needed in each year in key portfolios to support synthetic methane production. Lastly, the Company should seek
alignment from participants regarding price and availability forecasts and approaches for modeling risk.
Avista should provide an RNG procurement update in its next IRP Update including a comparison of projected and actual procurement;
2 RNG prices secured; a description of how the Company has leveraged other carbon markets to reduce RNG costs; and how the Company
is applying the environmental attributes of the RNG procured to CPP compliance. Further, where actuals volumes of RNG used for CPP
compliance are less than those projected, the Company should describe its plan to address those compliance deficiencies.
3 The next IRP should show a load forecast that reflects GCM trends by downscaling the model appropriately onto the Company's Oregon
service territory.
4 For the next IRP, engage the TAC regarding the GCM model downscaling methodology proposed for the next IRP.
5 For the next IRP, include a scenario of future weather informed by the RCP 6.0 model.
6 For the next IRP, include a scenario of no future customer growth beyond 2027.
7 Continue to work with TAC members on how to model customer growth impacts from HB 3409 and the potential for further Oregon
electrification policies reflecting those in place in Washington.
g For the next IRP, update its customer growth modeling to reflect the line extension allowance decision flowing from Docket No. UG 461.
9 For the next IRP, update its application of IRA credits to all applicable resources, including electrification resources.
Scenarios and sensitivities developed for the next IRP should include complex possible futures that capture plausible sources of risk due to
10 uncertainty; Avista should explore its resource portfolios against these scenarios. Avista should run stochastic analysis for price and
demand assumptions consistent within scenarios and report risk severity metrics for each scenario.
11 Avista should engage stakeholders and the TAC to seek input on any additional modeling methodologies or techniques to better capture
risk.
12 Avista should work with Staff and the TAC to investigate PLEXOS' ability to integrate risk aversion.
13 In its next IRP, Avista include a qualitative risk matrix in the next IRP that consolidates risk assessment for each resource in one chart and
provides a narrative risk assessment about each resource option's potential for negative outcomes due to uncertainty.
2025 Natural Gas IRP Appendix 422
�IIII��STa
6

OPUC Staff = Expectations
Expectation 2025 IRP
14 The Company should conduct a review, comparing projections from this IRP to actuals of their resource assumptions, quantitative
least-cost/least risk predictions, and forecasts.
15 Avista should work with the TAC to develop electrification modeling that reflects refined customer attrition assumptions.
16 The next IRP include electrification modeling assumptions that decrease capacity costs, distribution system costs, and other Discussion
appropriate expenses corresponding with reduced demand from electrification.
17 Future IRPs should include a scenario with significantly increased residential heat pump adoption and the corresponding shift in
winter load from the gas system to the electric system.
18 Avista should work with the TAC to more fully explore and model the potential of dual fuel heat pumps in the next IRP, for example
by ensuring that the use of some dual fuel heat pumps is represented in Monte Carlo risk analysis.
19 Before the next IRP, Staff expects Avista to work with the TAC to consider Staff's revised Electrification Incentive Strategy (see Discussion
Attachment A).
Staff expects Avista to work with the TAC to identify a PacifiCorp IRP scenario reflecting electrification that Avista might use to
generate a load forecast for its next IRP. Before the next IRP, Avista should work with PacifiCorp to collect the load forecasts used TBD - Need data
in planning that most closely reflects a building electrification scenario for the overlapping territories. With these load forecast
20 results, Avista should discuss with PacifiCorpsupporting comments regarding supply-side and demand-side resource impacts,
from Electric Utilities
pp g commentary g 9p
rate impacts, and associated GHG emissions with each scenario/portfolio. Avista should discuss with the TAC the extent to which
the Company might be able to model the equivalent in its next IRP.
21 Before the next IRP, Staff expects Avista to host electrification workshops, addressing the issues listed in Section 6.4 to support a
discussion on a proactive resource strategy.
22 Avista should update its distribution system planning practices and its future IRP processes as outlined in Attachment C.
23 Avista should apply distribution system planning practices as outlined in Attachment C to the Sutherlin project and should continue
to explore targeted electrification to offset demand at the Sutherlin gate station.
24 For future IRPs, the Company should discuss in a TAC meeting how Avista envisions avoided costs determinations aligning with
resource portfolios made up of higher priced fuels and declining natural gas, and how that will be reflected in its next IRP.
In the next IRP, Avista should include a workpaper of the fixed fees paid on each unit of capacity under contract and provide an
25 update on potential or existing plans to retire firm capacity contracts.
2025 Natural Gas IRP Appendix 423
III/V�STa
7

WUTC Staff = Recommendations
Review the Cascade Natural Gas general rate case final order with the TAC and the EAG together, consider how the core tenets of energy justice
1 apply to Avista's planning processes, and prepare to implement the order's equity framework. Dedicate time in the work plan for this topic.
• 2 Staff recommends that Avista consult with its equity advisory group to develop equity criteria for the siting of distribution projects and
reinforcements.
3 Include full accounting of the IRA in the 2025 IRP and provide sufficient time in the work plan for discussion within advisory groups.
• 4 Work with the Department of Ecology, Staff, and advisory groups, to discuss the implication of this "cap" and how it is likely to be achieved.
5 Provide a robust discussion of the"invest" portion of the"cap-and- invest" and discussion of the downstream impacts of CCA investments.
Account for and provide a narrative discussion regarding electrification driven by the CCA and discuss the CCA within its advisory group early in
6 the IRP development process.
7 Adopt representative concentration pathway RCP 8.5.
• 8 For greater clarity, for tables like Table 2.3, replace with time series graphs with appropriate box and whisker plots.
• g Revisit and update the winter peaking climate data and methodology as evidence and climate models improve.
10 Where the specifics of future energy codes are unknown, project a forecast trend that accords with statutory goals and mandates.
Develop a building stock attrition rate to represent the loss of customers due to buildings being demolished, remodeled without gas service due to
11 incompatible use cases, or otherwise leaving gas service unrelated to changes in the price competitiveness of gas services.
12 Adopt future building codes that are already imbedded in law as foundational assumptions for the primary demand forecast and not as a scenario.
• Analyze risks to customers and the distributional effects through the lens of equity, energy justice, and access to energy efficiency and
13 electrification resources.
Dynamically model the anticipated comparative costs between its natural gas services and electric utility services into the future as well as the
14 interplay of customers, by class, responding to changing comparative cost.
15 Incorporate the distributional analysis discussed below into the comparative cost analysis.
2025 Natural Gas IRP Appendix 424
��II/V�StA®
8

WUTC Staff = Recommendations
. . Recommendations
16 Continue to refine the methods and approach of leveraging potential assessments for achieving equitable outcomes.
17 Segment customers with different levels of gas to electric conversion costs rather than modifying costs only by scenario.
Potential 18 Consider audits of specific transportation customer sites to better understand current equipment and practices to refine estimates of
Assessments available potential for these customers.
19 Target outreach to the largest transportation customers to understand their likelihood of participating in future energy efficiency programs,
including to what extent and on what timeline, when considering program design.
20 Explicitly note costs of greenhouse gas emissions established in RCW80.28.395 when analyzing avoided costs.
Social Cost of 21 Clearly account for emissions occurring in the gathering, transmission, and distribution of natural gas, providing itemization, a total value of
Greenhouse these emissions, and the ratio of these emissions to throughput for the purposes of avoided cost calculations.
Gasses 22 Incorporate distribution system emissions data into Distribution Scenario Decision-Making Process criteria if applicable.
Calculations 23 Include both the cost of compliance with the CCA and the SCGHG for conservation in the base case in the 2025 IRP.
24 When calculating the natural gas energy efficiency target for 2024- 2025, use the avoided cost from the Social Cost of Carbon Case in
Appendix 6.4.
25 Consider hydrogen and landfill gas for the purposes of lowest reasonable cost analysis unless it can demonstrate a reason not to consider
Alternative these fuels.
Fuels 26 Convert figures similar to 4.16 through figure 4.21 to time series graphs featuring box and whisker plots.
27 Highlight and offer appropriate cautions in its analysis wherever PLEXOS yields results or behaviors that would be unlikely to be anticipated or
enacted by a human planner.
IRP Modeling 28 Highlight and offer appropriate caution in its analysis wherever PLEXOS uses resources in its portfolio in a manner that does not accord with
current best practices or current technological means.
29 Rely upon human expertise to vet and verify all results generated by PLEXOS.
30 Consult with the TAC and parties to the GRC to discuss what a decarbonization plan should entail, submit a specific workplan, and provide a
Decarbonization decarbonization plan in the 2025 IRP.
Plan and 31 Refine the electrification analysis with input from interested persons.
Electrification
Analysis 32 Refine assumptions around electrifying loads and run additional sensitivities that illuminate a range of possible costs of electrification
depending on how loads electrify. 2025 Natural Gas IRP Appendix 425
9
�MISTA®

VIS TA°
Secondary Actions and
Attachments

OPUC Staff = Requests
Request 1 : Future IRPs should include a clearer explanation of the PRS, and a more transparent presentation
of the assumptions and processes used in creating the PRS, including examples noted by Staff.
Request 2: Staff requests Avista engage the TAC in discussion of the value of NPVRR analysis relative to
levelized-cost analysis.
Request 3: Avista engage the TAC in considering the merits and drawbacks of modeling state specific resource
and system investments.
Request 4: Staff requests that the latest information on possible distribution projects, including any proposed
traditional investments or proposed NPA, be included in future IRP Updates.
Request 5: Staff requests that the possible impacts (at least on the Company's revenue requirement and
scenario analysis) of line extension allowance elimination be taken up by the TAC with the goal of determining
how to best reflect expected impacts in future IRPs.
Re
qquest 6: Staff requests that the Company report to the TAC in late 2024 on the low-income hybrid heating
pi lof including relevant program details, pro ress to-date, lessons learned, findings about the potential of such a
program to meet CPP compliance and to migate upward rate pressure, and learnings on how to model such a
program in future IRPs.
Request 7: Staff requests Avista vet demand response modeling parameters (such as costs, increments,
potential, and ramp rates) with TAC members.
Request 8: Staff requests that Avista engage the TAC in a discussion of how the value of Interruptible loads can
be folded into resource planning.
Request 9: Staff requests Avista engage a representative set of Interruptible customers to study interest in
participating in demand response offerings, and under what conditions, with results to be shared with the TAC.
Request 10: In the IRP Update, Staff requests that Avista include a table of expected CPP compliance costs.
2025 Natural Gas IRP Appendix 427
�IIII��STa®
11

OPUC Staff - Attachment A
• Ratepayer Incentive Value
The Ratepayer Incentive Value includes both the cost of the ratepayer to convert and the benefit the ratepayer's decision to electrify provides to gas system operations and
downstream costs. Staff expects the feasibility of conversion to be constrained by the equipment lifecycle costs (equipment costs and operation costs over the lifetime of the
appliance) and available electric grid capacity. Equipment cost calculations could foreseeably leverage precedent used within the Docket No. UM 1893, available policy
incentives, and data collected from regional electric appliance sales and Energy Trust of Oregon heat pump programs. Staff is not convinced that electric rates are the best
indicator of operation costs. Instead, Staff requests Avista work with Energy Trust and electric utilities to consider bill impacts or other metrics to measure operation costs by
end-use. In any event, given the sensitivity of lifecycle costs to region, Staff stresses that Avista use regionally appropriate efficiencies, equipment and operation costs, and
weather forecasts for Avista's service territory.141 Moreover, Staff believes that understanding the Ratepayer Incentive Value of electrification will require some form of
scenario and data sharing between gas and electric utilities to identify where electrification is feasible based on available capacity on the electric grid to handle the new entry of
electric appliances. To determine the benefits the ratepayer provides to the system through their decision to electrify, Staff requests the Company consider how the decision
provides downstream benefits such as reduced emissions, reduced need for higher-cost alternative fuels, reduced transportation and distribution costs over the long term. The
decision to electrify may also provide reliability benefits to the gas system during winter peak through released firm pipeline capacity. In determining a compensation cost for
these savings and gas system operation benefits Staff sees benefit in considering existing electric sector incentives, including time-of-use rates, net metering, and capacity
payments. Staff recognizes that the price to switch out appliances and electric rates rising above marginal cost are key considerations in a property owner's decision to
electrify. If the benefit of the ratepayers' investment is greater than the costs, it can indicate new entry of the electric unit and a corresponding retirement of the gas unit.
• Policy Incentives
Policy incentives include external, non-ratepayer funding sources. These can supplement an incentive strategy without impacting gas rates. For example, the IRA provides tax
credits and rebates to reduce the purchase cost for electric panel upgrades and heat pumps, whose high costs can be a barrier to electrification. Notably, maximizing IRA
incentives is crucial in the near term, as available IRA incentives decrease annually and are unavailable after 2032. As shown in the figure below, in the workpapers
accompanying the IRP, Avista forecasts that the cost of electrification will increase year over year and spike in 2032 with the termination of IRA financing. This suggests that it
will be incrementally more expensive for Avista to incentivize electrification over time. Figure 7 below shows Avista's forecasted cost for electric space heat inclusive of a 50
percent reduction in conversion costs for IRA incentives and increasing electric rates.
• Company Cost Value
The Company Cost Value portion of the incentive strategy looks at the cost to the Company to proactively incentivize electrification. In other words, what portion of the
Ratepayer Incentive Value is the Company willing to pay? Staff recognizes that electrification reduces consumption. This manifests as a cost to the LDC through reduced
returns and lost capital investment opportunities. Unless the company can anticipate a return on the investment, their willingness to incentivize electrification is lower because
of these reduced revenue requirements. Using avoided cost calculations may help to understand Avista's willingness to pay. Staff anticipates working with the Company to
deepen conversation around electrification and avoided cost within the Docket No. UM 1893.
• Conclusion
As discussed in more detail in Section 6.4, Staff is interested in hearing from stakeholders when identifying the right incentive level. Staff recognizes that this will likely require
the sharing of data and scenarios between gas and electric utilities and recommends possible pathways in Section 6.3. Moreover, an electrification incentive strategy should be
considered alongside other energy efficiency and weatherization programs.
2025 Natural Gas IRP Appendix 428
12
III/VISTA

OPUC Staff - Attachment C
The Company should update its DSP practices and IRP processes to include:
1 . Future distribution system planning should identify the rationale for projects as either Safety/General System Reliability, or
Customer Growth/Reliability Related to Growth. a. When proposing growth-driven projects in IRPs the utility should be
prepared to present project data on: relationship to CPP compliance strategy, modeling and verified measurement, local load
forecast, and assessment of alternatives through the NPA framework.
2. Future distribution system planning should include an NPA framework in Oregon. The framework should include:
NPA analysis will be performed for supply-side resources (these include but are not limited to all resources upstream of Avista's distribution
system and city gates, and supply-side contracts) and for distribution system reinforcements and expansion projects that exceed a threshold
of$1 million for individual projects or groups of geographically related projects (a group of projects that are interdependent or interrelated).
b. NPA analysis will include cost benefit analysis that reflects an avoided GHG compliance cost element consistent with a high-cost estimate
of future alternative fuels prices. Non-Energy Impacts must be included as part of the NPA analysis.
NPA analysis will include electrification, targeted energy efficiency, targeted demand response, and other alternative solutions.
NPA analysis should look forward five years to allow ample time for evaluation and implementation.
NPA analysis will include an explanation of solutions considered and evaluated including a description of the projected timeline and annual
implementation rate for the solutions evaluated, the technical feasibility of the solutions, and the strategy to implement the solutions
evaluated.
f. NPA analysis should include an explanation of the resulting investment selection (either NPA or a traditional investment) including the costs
and ranking of the solutions, and the criteria used to rank or eliminate them. i. If a NPA is not selected and the reason is insufficient
implementation time, it should include steps the Company will take to perform NPA analysis to provide sufficient implementation time for
future projects.
3. Future IRPs should include the results of distribution system planning, including project data and NPA analysis for any
proposed traditional investments, and NPA analysis for any proposed NPA.
4. Future IRPs should include a database containing information about feeders, in service dates of pipes, and lowest recent
observed pressures.
2025 Natural Gas IRP Appendix 429
13
'eIIII Basra®

�� i'ISTA°
Modeling and Assum t 'ions
Overview

Least Cost Resource Solve Model Risk Model
_�xpected Load Model L L (differing load future scenarios)
r7
Scenario Assumptions
End Use Risk
Efficiencies / Objectives
Stock Rollover 7 and Input
Climate Program/Policy Constraints
W
m
U
O
Current Demand Side
Weather Demand Side Resource
o Resources Options
Current Supply Side Preferred
source
Supply Side Resource Strategy Oj>
Resources Options
ILL
I F Electri —;Least Cost Solve
Q FFEnd Use Load Costs for
Forecast E: added I /Avoided Costs IRP
customers
n -Al

Load Assumptions
• PRS load input will rely on current known state policy, codes and requirements
WA SBCC will be included in load forecast baseline
Line extension program expirations will be included in forecast baseline
2027 end date in Oregon
2024 end date in Washington
• Hybrid heating begins below 40 degrees Fahrenheit
Chosen as an average between furnace manufacturer coefficient of performance values (COP)
Value is also used by fundamental forecast houses in their electrification evaluations
• The end use model can select higher efficiencies if cost effective or standard at rollover
Model will select cost effective pathway (gas or electric) and distribute load
• Scenarios will estimate risk of differing load expectations
2025 Natural Gas IRP Appendix 432
3
III/v�sra

Cost Assumptions
All quantifiable current and estimated costs:
• Interstate pipeline transportation
• Storage
• Exgumas)
ected cost of natural gas by supply basin (AECO, Malin, Rockies, Stanfield, Station
2,
• Alternative fuels (RNG, Methanation, Hydrogen — all forms, carbon capture)
• Compliance mechanisms to climate programs (Allowances, Offsets, CCls)
• Social cost of carbon @ 2.5%, where applicable
• Economic non energy impact (NEI) adders
• Energy Efficiency per the CPA
• Demand Response potential costs per the CPA
• New capital distribution projects by area
• Maintaining the LDC
• Electricity cost by area (including distribution, transmission additions)
• Electrification (includin efficiencies, costs by area, including distribution and
transmission additions
2025 Natural Gas IRP Appendix 433
�IIII��STa®
4

Output
• An average rate, with power costs, will be provided by
scenario
• Emissions by scenario
• A levelized cost by scenario
• A net present value revenue requirement (NPVRR)
• Risks
• Energy Burden
2025 Natural Gas IRP Appendix 434
�IIII��STa®
5

Scenarios
Scenarios — Deterministic & Description
Monte Carlo
PRS Our expected case based on assumptions and costs with a least risk and least cost
resource selection. This scenario includes all known policies and orders from Idaho,
Oregon and Washington. Assumes 4.5 RCP weather.
High Growth on Gas System A high case to measure risk of additional customer and meeting our emissions and
energy obligations
High Electrification The highest expected conversions to the electric system. Electric IRP indicates
80% loss by 2045
PRS - Includes CPP PRS assumptions, but includes the CPP expectations going forward from 2025
No Climate Programs PRS assumptions with no climate programs
Low Natural Gas Use Case This scenario will include high electrification, with the 8.5 RCP for weather, high cost
of alternative fuels and a high cost of allowances in WA.
2025 Natural Gas IRP Appendix 435
* �IIII��STa®
6 Each scenario will have a rate per class, a cost with power included, emission and energy burden

Scenarios - Deterministic Only
Scenarios — Description
Deterministic Only
Low Alternative Fuel A scenario to measure resource selection with a lower-than-expected set of Alternative
Costs Fuel costs by source
High Alternative Fuel A scenario to measure resource selection with a higher-than-expected set of Alternative
Costs Fuel costs by source
High Natural Gas Prices Higher than expected prices for natural gas
Average Case Weather Non climate change projected 20-year history of average daily weather and excludes
peak day
High CCA Costs Considers a high cost for allowances in Washington
2025 Natural Gas IRP Appendix 436
* �IIII��STa®
7 Each scenario will have a rate per class, a cost with power included, emission and energy burden

Scenarios - Deterministic Only
Scenarios — Description
Deterministic Only
RCP 8.5 Weather Weather will use the RCP 8.5 future
RCP 6.0 Weather Weather will use the RCP 6.0 future as the average between RCP 8.5 and 4.5
Resiliency Supply will be selected to create a resilient system
No New Natural Gas Restrict customers after line extensions expire in Oregon and Washington to 0 growth
Hybrid Heating A scenario to include hybrid heating for temperatures below 40 degrees Fahrenheit
Diversified Portfolio This scenario will include electrification, 25% of supply from RNG, 25% of supply from
methanation and 7% from hydrogen all after 2035.
Social Cost of Carbon A scenario to value resources in all locations using the Social Cost of Carbon @ 2.5% and
includes upstream emissions
2025 Natural Gas IRP Appendix 437
/III
8 *Each scenario will have a rate per class, a cost with power included, emission and energy burden �11''MIsra®

Modeling Risk
• 18 total scenarios
Deterministically solve a set of resources to meet variability in the
scenarios for a stochastic set of futures
• Run 500 monte carlo futures for the 4 distinct load scenarios
to determine risk
• Efficient Frontier may be used to select least cost and least
risk solution
2025 Natural Gas IRP Appendix 438
�IIII��STa®
9

Adioiffi: 4 W Fm!FmArAt&
Avista CROME High Level Overview
Comprehensive Resource Optimization Model in Excel
Michael Brutocao
Natural Gas Analyst NFEF V Rpm

Timeline : IRP Modeling Software
Prior to 2023 2023 IRP 2025 IRP
PLEAS
BV ENERGY E%EMPLAR
bb-
pp-
4A
SENDOUT° PLEXOS° Avista
CROME
2025 Natural Gas IRP Appendix '
2

High Level Overview
Select scenario-
specific specific data
INPUTS AND Avista CROME REPORTS
ASSUMPTIONS
• Inputs and assumptions • Inputs, assumptions,
• CROME solution data
are stored here. and constraints are updates templates for
brought together. summary statistics and
• Data is prepared for graphics.
CROME. • Decision points are
optimized to produce
least-cost solution.
2025 Natural Gas IRP Appendix '
3

Solving for Residential , Commercial , and Industrial Loads
Storage
Gross Energy Storage
Demand Withdrawal
Storage Third Party
DSM Injection Natural Gas Compliance
Mechanisms
Net Energy Alternative Program
Demand Fuels Compliance
Mechanisms
Demand Pipeline
Response Electrification Network
Net Load 1 Served Load * Emission
.................................................. ...................................................
Constraints
Unserved Non-
Load Compliance
* NEI cost consideration
1 Cost of expected distribution projects 2025 Natural Gas,RPAppendix
4

Solving for Transport Customer Loads
*r Storage
Gross Energy rage
Demand
Natural Gas Third Party
Storage
DSM Injection (From Service Compliance
Supplier) Mechanisms
Net Energy f Alternative Program
�• Compliance
Demand ' : Fuels
•. • ' Mechanisms
Demand Electrification Pipeline
Response Network
Net Load Served Load Emission
.................................................. ..................................................
Constraints
Unserved Non-
Load Compliance
2025 Natural Gas IRP Appendix
5

NET LOAD
2025 Natural Gas IRP Appendix '
6

GrossDemand
Considerations: Number of customers by end-use
Gross Energy Base use per customer
Demand
Heating use per customer
DSM Weather
Net Energy
Demand Optimization Decision: N/A
Demand
Electrification
Response Points: All modeled areas and customer
classes
Net Load
Frequency: Daily
2025 Natural Gas IRP Appendix '
7

Demand Side Management
Considerations: Avoided cost by area and customer
Gross Energy class
Demand
Number of customers by end-use
DSM CPA from AEG/ETO
Net Energy Inputs: UCT (ID), TRC (WA, OR)
Demand
Demand
Electrification Response Points: All modeled areas and customer
classes
Net Load
Frequency: Daily
2025 Natural Gas IRP Appendix '
8

Demand Response
Considerations: Cost
Gross Energy Available "supply" by program, area
Demand
and customer class
DSM
Optimization Decision: Quantity "purchased"
Net Energy
Demand
Decision Points: All modeled areas and customer
Demand Electrification classes
Response
Net Load Decision Frequency: Daily
2025 Natural Gas IRP Appendix
9

Electrification
Considerations: Cost
Gross Energy Available "supply"*
Demand
DSM Optimization Decision: Quantity "purchased"
Net Energy
Demand Decision Points: Residential and commercial classes
(OR, WA)
Demand
Electrification
Response
Decision Frequency: Annual
Net Load
* This is constraining the optimization decision 2025 Natural Gas lRPAppendix
10

SERVED LOAD
2025 Natural Gas IRP Appendix
11

_..----.._.._ _ _.._.._.......
......
Storage Natural Gas
Considerations: Cost
Storage
Withdrawal
Optimization Decision: Quantity purchased
Storage Natural Gas
Injection
Decision Points: AECO Stanfield
Alternative
Fuels Malin Station 2
Pipeline Rockies Sumas
Network
Decision Frequency: Daily
Served Load
Unserved
Load
2025 Natural Gas IRP Appendix '
12

_..----.._.._ _ _.._.._.......
......
Storage Alternative Fuels
Considerations: Cost
Storage Available supply
Withdrawal
Max blend percent *1
Storage Natural Gas
11,Injection
Optimization Decision: Quantity purchased
Alternative
Fuels
Decision Points: Hydrogen (7 forms)
Pipeline
Network RNG (5 forms)
Synthetic methane (3 forms)4
Served Load
Decision Frequency: Annual
Unserved
Load
* This is constraining the optimization decision
1 A daily constraint on the volume of hydrogen blended into pipebi r eGasIRPAppendix
13 Model decision frequency to be determined by alternative fuel study results

_..----.._.._ _ _.._.._.......
......
Storage
Considerations: Min/max volume
Storage Max daily injection/withdrawal
Withdrawal
Capital & overhead
Storage
Injection Natural Gas Carrying rate
Alternative
Fuels Optimization Decision: Quantity injected/withdrawn
Pipeline
Network Decision Points: Jackson Prairie
Served Load
Decision Frequency: Daily
Unserved
Load
* This is constraining the optimization decision 2025 Natural Gas lRPAppendix
14

_..----.._.._ _ _.._.._.......
......
Storage Pipeline Network
Considerations: Flow capacity
Storage Reservation rate
Withdrawal
Variable rate (flow charge)
Storage
Natural
Injection Gas Fuel loss
Alternative
Fuels Optimization Decision: Segment flow
Pipeline
Network Decision Points: All pipeline segments in network
Served Load
Decision Frequency: Daily
Unserved
Load
* This is constraining the optimization decision 2025 Natural Gas lRPAppendix
15

_..----.._.._ _ _.._.._.......
......
Unserved
Storage '
Considerations: Cost
Storage
Withdrawal
Optimization Decision: Quantity unserved
Storage Natural Gas
Injection
Decision Points: All modeled areas and customer
Alternative
Fuels classes
Pipeline
Network Decision Frequency: Daily
Served Load
Unserved
Load
2025 Natural Gas IRP Appendix '
16

EMISSIONS
2025 Natural Gas IRP Appendix '
17

Natural Gas & Alternative Fuels
Natural Gas Third Party Considerations: Carbon emissions
(+Upstream Compliance
Emissions) Mechanisms
Alternative Program Optimization Decision: Quantity purchased
Fuels Compliance
Mechanisms
Decision Points: Same as in served
Emission Decision Frequency: Annual, daily
Constraints
Non-
Compliance
2025 Natural Gas IRP Appendix '
18

_-- .---------...-..-.--...-..-.- -.�..
• Party Compliance
Third Party Considerations: Cost
Natural Gas Compliance
Available supply
Mechanisms
Program
Alternative
Fuels Compliance
Mechanisms Optimization Decision: Quantity purchased
Decision Points: Renewable thermal credits (3 forms)
Emission Carbon capture (4 forms)
Constraints
Decision Frequency: Annual
Non-
Compliance
* This is constraining the optimization decision 2025 Natural Gas lRPAppendix
19

_-- .---------...-..-.--...-..-.- -.�..
' • Compliance Mechanisms
Third Party Considerations: Cost
Natural Gas Compliance
Available supply
Mechanisms
Program
Alternative
Fuels Compliance
Mechanisms Optimization Decision: Quantity purchased
Decision Points: Allowances (CCA)
Emission Offsets (CCA)
Constraints CCIs (prior CPP)
Non- Decision Frequency: Annual
Compliance
* This is constraining the optimization decision 2025 Natural Gas lRPAppendix
20

_-- .---------...-..-.--...-..-.- ----------------
Non-Compliance
Third Party Considerations: Cost
Natural Gas Compliance
Mechanisms
Alternative Program Optimization Decision: Quantity
Fuels Compliance
Mechanisms
Decision Points: Climate Commitment Act
Prior Climate Protection Program
Emission
Constraints Decision Frequency: Compliance period, annual (CCA)
Non-
Compliance
2025 Natural Gas IRP Appendix '
21

EEV� w
I
2025 Natural Gas Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Wednesday, June 5, 2024
Virtual Meeting
Topic Time (PTZ) Staff
Feedback from prior TAC 9:00 Tom Pardee
Distribution System Modeling 9:10 Terrence Browne
OPUC Recommendation on NPA 10:10 OPUC Staff
Targeted Energy Efficiency 10:35 ETO
Weather Futures and Peak Planning 11 :00 Tom Pardee
TAC feedback 11 :50 All
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2025 Natural Gas IRP Appendix 460

jlr��
000�-
0..,-0000
Distribution System Planning.
Terrence Browne PE, Principal Gas Planning Engineer
Natural Gas Technical Advisory Committee
June 5, 2024
2025 Natural Gas IRP Appendix 461
1

Mission
• Using technology to plan and design a safe, reliable, and
economical distribution system
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2025 Natural Gas IRP Appendi
2

Service Territory and Customer Overview
• Serves electric and natural gas customers in eastern Washington and northern Idaho,
and natural gas customers in southern and eastern Oregon
— Population of service area 1 .7 million
► 414,000 electric customers
Kettle Falls • Sandpoint ► g
378,000 natural as customers
•
® • Noxon MONTA,
WASHINGTON
Spokane• •Coeur d'Alene
•
Missoula
•Othello -�. •
Jackson Prairie
Natural Gas Storage Pullman • •Moscow
Clarkston •Lewiston
Stevenson Goldendale
•Grangeville
•
Portland La Grande •
•
salcm
IDAHO
OREGON
6 Roseburg
' dford
Electric Natural Gas 2o25&1teS,�Li. ir# nAdenN,atural Gas
3

, M Planning Models
• 8,000 miles of distribution main
• 120 cities
• 40 load study models
aka a oZssok .,
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2025 Natural Gas IRP Appendix '
4

5 Variables for Any Given Pipe
Pup Pdown
Q M*00. I D
2025 Natural Gas IRP Appendix 465
5

Scope of Gas Distribution Planning
Supplier Pipeline
0
Gate
Sta. High Pressure Main
Reg. Reg. Reg.
0 0 0
L4
0
o0
Distribution Main and Services
2025 Natural Gas IRP Appendix 466
6

Scope of Gas Distrib . Planning cont.
0
0
Gate � �
Gate
Sta. Sta.
Reg. Reg. Reg.
0 0 0
.
L
_ o o Gate
0 El
Sta.
Reg. Reg.
2025 Natural Gas IRP Appendix 467
7

SynerGi (SynerGEE , Stoner) Load Study
• Simulate distribution behavior
• Identify low pressure areas
• Test reinforcements against future growth/expansion
• Measure reliability
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Creating a Pipeline Model
• Elements
— Pipes, regulators, valves
— Attributes: Length , internal diameter,
roughness
• Nodes
— Sources, usage points, pipe ends
— Attributes: Flow, pressure
oaa. e.- __ , :quo•n .. . .•.i ... .. e
46
z fii
t
z i
2025 N ural Gas IRP ppendix

EstimatingCustomer Usage
• Gathering Data
— Days of service
— Degree Days
— Usage
— Name, Address, Revenue Class, Rate Schedule . . .
r �
2025 Natural Gas IRP Appendix
10

Estimating Customer Usage cont.
Avg. Daily Heating Cooling
Temperature Degree Days Degree Days
('Fahrenheit) (HDD) (CDD)
• Degree Days 85 20
80 15
— Heating (HDD) 75 10
70 5
— Cooling (CDD) 65 0 0
60 5
• Temperature - Usage Relationship 50 10
— Load vs. H D D's 40 15
25
— Base Load (constant) 35 30
30 35
— Heat Load (variable) 20 45
— High correlation with residential 10 55
5 60
4 61
0 65
-5 70
-10 75
-15 80
2025 Natural Gas IRP Appendix 471
11

Load vs. Temperature
II �III
1-1 71:1
y = 0.0129x + 0.1175
Heat Base '
CI.40
. l
0.20
0.10
0.00
0 5 10 15 20 25 30 35 40 45
Heating Degree Days
2025 Natural Gas IRP Appendix 472
Summary 109735 1103678 Z 114268 114279 Chartl 133049 ,( 156920 ,( 161549 208478 �� j

Monitoring Our System
• Electronic Pressure Recorders
• Daily Feedback
• Real time if necessary
• Validates our Load Studies
� t
lr ,
2025 Natural Gas IRP Appendix
13

Validating Model
• Simulate recorded condition
• Electronic Pressure Recorders
— Do calculated results match field data?
• Gate Station Telemetry
— Do calculated results match source data?
• Possible Errors
— Missing pipe
— Source pressure changed
— Industrial loads
2025 Natural Gas IRP Appendix
14

i i
_ •E.Pressure 1 Interval High
y I t � ■= 52.90
J 1 J
W
Pressure 1 Interval Low
2.5
SI
or
o
-27 2014 8:33:59.219 A 14.00 days 10 2014 8:33:59.219 AM
P1 Interval High
P1 Interval Low

Pressure 1 Interval Hig
I '
■
01-MO 14 8:39:14.465 AM
• P1 Interval High
• ♦ P1 Interval Low

do
55.00 E.Pressure 1 Interval High
42.47
5 0; 4 i �, �'~4 'L NONE PSIG
LL.] Ld f
� � �• ) L� l� J� ri L E.Pressure 1 Interval Low
u < < < 38.5
i* w
r
0.
01-27-2014 8:33:04.271 AM ,14.00 day s 02-10-2014 8:33:04.271 AM
• P1 Interval High Ta"
♦ P1 Interval Low

Planning Criteria - 2023
• Reliability during design HDD
— Spokane 76 HDD (avg. daily temp. -11 ' F)
— Medford 49 HDD (avg. daily temp. 16' F)
— Klamath Falls 72 HDD (avg. daily temp. -7' F)
— La Grande 72 HDD (avg. daily temp. -7' F)
— Roseburg 46 HDD (avg. daily temp. 19' F)
• Maintain minimum of 15 psig in system at all times
— 5 psig in lower MAOP areas
— 3 psig in Medford 6 psig systems
2025 Natural Gas IRP Appendix
18

Fixes and Reinforcements
• Identify Low Pressure Areas
— Number of feeds
— Proximity to source
• Looking for Most Economical Solution
— Length (minimize)
— Construction obstacles (minimize)
• Lead Times:
— Design and engineering; 12 months
— Real estate, permits, and environmental ; 6-24 months
— Material ordering and delivery; 3-6 months
2025 Natural Gas IRP Appendix
19

Non -Pipe Alternatives (NPAs)
• System Pressure Uprates
• Conservation
• Electrification
202 endix
20

NPA: System Pressure Uprates
• Objective
— Raise source pressure to increase capacity
• Process
— Deep dive into records
— Series of leak surveys
• Challenges
— Remaining opportunities?
• Lead time
— 6-12 months
Pup Pdown
C__Q :D I D
21

NPA : Conservation
• Objective
— Reduce customer demand on distribution
• Process
— Targeted Load Management (TLM) programs
• Identify opportunities and energy efficiency potential
• Implement energy efficiency measures
• Challenges
— Minimal benefits realized at distribution locations
— More effective on supply side
• Lead time Gate
— 3-5 years
Reg. Reg. Reg.
2025 N tur 1 Gas IRQP Append o °°
22 Q

NPA: Conservation
• Results of Energy Trust TLM analysis (Oct 5th 2023)
Avista TLM : Total Potential and Program Activity
Area Utility Target Total Efficiency Historic Annual
Goal Resource Average
Medford 691 479 11
Sutherlin 121 158 2
peak hour therms
three-year total efficiency resource; cost-effective achievable potential
• Resource assessment modelling results demonstrate there is not enough
peak reduction to meet AVI load reduction targets.
The Medford AVI target is 144% of resource potential.
➢The Sutherlin AVI target is 77% of resource potential.
• Program history shows the targets are 60x greater than a typical year of
program activity.
2025 Natural Gas IRP Appendix
23

NPA: Conservation
• Results of Energy Trust TLM analysis (Oct 5th 2023)
Avista TLM : Forecast Using NWN Pilot Results
Area Utility Target Pilot Total Resource Pilot Historical
Goal Results Results
Medford 691 66 63
Sutherlin 121 18 12
I
our therms
s three-year TLM project
s needed to achieve tar ets at NWN ilot rate
N Pilot achieved 4% of resource potential in two years of enhanced
ntives.
neralizing to a three-year project this equates to roughly 12% of Avista's targets.
N Pilot nearly doubled historical acquisition.
is would result in about 9% of Avista's targets in a three-year period.
2025 Natural Gas IRP Appendix
24

NPA : Electrification
• Objective
— Eliminate customer demand on distribution
• Process
— Identify customers in deficient areas
— Transition to electric appliances/load
• Challenges
— Transition may be expensive (cost of appliances)
— Limited capacity and infrastructure of electric utility
• Who pays for upgrade
• Lead time
— 1 -?? years
Reg�� Reg.`; ;",Reg. ,
❑ JET
7 _-;_ o 0
❑ 2025 Natural Gas IRP Appendix
I
25 _--

Areas Currently Monitoring for Low
Pressure and Proposed Solutions*
• Medford 6 psig system , OR
• Airway Heights, WA
• South Hill Spokane, WA
• Schweitzer Resort, ID
• Moscow, ID
• *Notes:
— List not comprehensive
— projects are subject to change and
will be reviewed on a regular basis
2025 Natural Gas IRP Appendix
26

City Gate Stations Currently Monitoring
and Proposed Solutions*
• Sutherlin , OR: rebuild/enhance in 2024+
• Malin , OR: observe, rebuild/enhance in 2025+
• Medford , OR: work with pipeline to increase capacity
• Rathdrum — Chase , ID : rebuild/enhance in 2024+
• Pullman , WA: work with pipeline to increase capacity
• *Notes:
— List not comprehensive
— projects are subject to change and will be reviewed
on a regular basis
2025 Natural Gas IRP Appendix
27

Questions and Discussion
V
•1, a: r
Mission 4W'
Using technology to plan and design a r :
safe, reliable, and economical distribution
system
2025 Natural Gas IRP Appendix
28

Avista ' I
STAFF'S PROPOSAL FOR
NON PIPE ALTERNATIVES
-= Nick Sayen
Senior Utility Analyst
June 5, 2024
Oregon
Public Utility
Commission
489

Oregon
Public Utility
CommissionStaff' s Proposal
... .Staff expects the Company to update its distribution system
planning practices and IRP processes to include:
• Guidance from Attachment A to Staffs Report in Order No.
23-023;
• Direction provided by Order No. 23-281;
• Practices agreed to through Stipulation Item 21 in Order No.
23-384; and
• Several of the extensions of Stipulation Item 21 suggested
ODOM by Climate Advocates.
Specific elements of Staffs expectation are included in
Attachment C. Staff emphasizes this expectation does not
.. include significant, new concepts. With the exception of three
items (2e., 2f., and 3) all of these practices have already been
included in Commission Orders. Staffs expectation simply
assembles these concepts into a more cohesive package.
Staff's Second Errata Final Comments on 2023 IRP (Docket No. LC 81), page 45,
2025 Natural Gas IRP Appendix 490
https://edocs.puc.state.or.us/efdocs/HAC/Ic81hac326154032.pdf

Oregon
Public Utility
Commission Attachment
1. Future distribution system planning should identify the rationale for projects as either
Safety/General System Reliability, or Customer Growth/Reliability Related to Growth.
a. When proposing growth-driven projects in IRPs the utility should be prepared to
present project data on: relationship to CPP compliance strategy, modeling and
verified measurement, local load forecast, and assessment of alternatives
through the NPA framework.
Attachment C
The Company—ld upd.te its D5P practices and I RP processes to include:
re tllrtribution system planning mould itlelMN the rationale for pmjecrs as edM1er
1 Safery/General System Rdiab.ift or Cu­Gr h/Reliability Related M Growth.
a Wh-proposing growM-0dven pmlec[s in IRPs Me unliry snoultl be preparetl[o
preuntproleddafa on:reNnonSM1ip IO CPP compliance rtra[egy,motleling and
venNed measuremem,lrcal load roremn,and azsessmem of alcernativez
Mrvugn Me NPA famework.
g.F re tlirtnbutian system planning znoultl inclutle an NPA framework in Oregon.The
fiamework M.Id include:
a.NMa Ice Mwill be performed for supplYside resources(M indude but are
of limifetl fo all resources upstream of AWSG's tlirtrlbution system aM my
gaces,ands ly id,mmracts)aM ror ror%mill pml disbibutlon Nrtem reiMorcemeMs and
an ects[Mt eueed a Mresnold of ion indMdual projects or
gmupslof geoR hK ly related prgects(a group of projects Mat are
terdepentlent m iMemelated).
b.-
ill will include cost bi,l a 1al Mat reflects and ided GHG
ompliance cast element cansis ..a M1igtl-wrt estimate of future
alternative fuels pdm.No Energy Impacts must hero Il as part of Me NM
analysis.
c. NPA analKis willmclutle eleRrMotian,targeted energy dfid.---d
Je response,and abler altematiW mlutions.
d.N analKis snwltl lookforwaN rive years toallowamge time for evaluation
aM implemem to
NM analnls will inclutle an eaplanation of solutions considered and ev Iu d
ndMin¢a aesoiptian of Me pmjectea nmebne and annual implememanon rate
rortne solutions evaluaceqtheceshnical feasibility of the solutions,antl Me
rategy fo imgemenf Me solutions eyawaee.
f. N analna snoam mdude anewmnationgmeresuMng lnvesrmem selection
lenher NM ora tmdidonalimenment�ii—diig them and ranking of Me
wlution antl the aderia u-to rank or eliminate Mem.
H a NPA.lwt ulecfetl antl fM1e reamn k insufficient implementation
time,it Mould indude steps Iii Com willtake Mperform NPA
nalysista prwitle sufidem implementation time rorfuture projMs.
3.F PM anuaklysrcis eM1reulsofMrtdbutt.nsrtemplanni inclutlinproj.t
db anld Mor proposed trMNonal invertmerrts,and NM analysis ror airy
proposM NPA
a.Future IRPs Mouldwdutle ada[abase containing information about leetlerz,in service
dates of pipes,antl lowert recent oburvetl pressures.
2025 Natural Gas IRP Appendix gg 491

Oregon
Public Utility
Commission Attachment
2. Future distribution system planning should include an NPA framework in Oregon. The
framework should include:
a. NPA analysis will be performed for supply-side resources (these include but are
not limited to all resources upstream of Avista's distribution system and city
gates, and supply-side contracts) and for distribution system reinforcements and
expansion projects that exceed a threshold of $1 million for individual projects or
groups of geographically related projects (a group of projects that are
interdependent or interrelated).
b. NPA analysis will include cost benefit analysis that reflects an avoided GHG
compliance cost element consistent with a high-cost estimate of future
Attachment C
alteralternative fuels prices. Non-Energy Impacts must be included as part of the NPA 'pdafeits°SPprarhrea.ld idproaeesea---
native planning snp°la ieendry the ratbnale br pmiem as archer
I System eliabilo,,or Curtomer Growth/ReliabilityR tedtp Growth.
Xopozing growM-0men protects in IRPs 1M1e unliry shoultl be prepared[o
analysis.
t projett eats on:relanonihipto CPP compliance strategy,motleling and
meas i,f P, t,Ircalload bremrt,and a mem of al erne ez
sMe NPA ramework.
Non system planning znoultl include an NPA framework in Oregon.The
c. NPA analysis will include electrification, targeted energy efficiency, targeted Nldi°°°ee
alms win DQ performed for supplYsiae resources(these ndutle bm are
ftetl to all resourtes upstream of AvisG's tlirtribution syrtem aM dry
demand response, and other alternative solutions. ndapPpNaide�mra�'a-h.W bN°niemmMd..l n°
ion pmied:tna eweea a titre:hold or Si mabon ror baiyiapal proem w
of geographically relafetl prgxN la group N projects Thal are
pendent or infemelatedf.
b.XManalysis will'mdude cost bi,a analyshi—regem iii, dGHG
omplianci,cost element c nsis —a high-wrt estimate of flrtura
alternMNe fuels pram.Non-Energy Impacts must be in 1l as part or the NPA
analysis.
c. NPA analysis willmlutle electrNiotion,largetetl energy dhdeooy,.Riftd
eemana mpnn:e,and purer Ntematie wwmnz.
e.N analysis snwltl look brwaN rive years toallowamge time for evaluation
and implememahon.
NPA analysis will include an eaplanadon&wlutions considered and evaluated
inclutling a eescdption of Ne pmjeRetl timeline and annual implememation rate
brine wlutians evaluateqthetezhnical feasibility of the wlunons,antl the
rategy fo imgement the wlptions eyawaee.
f. N analKis snwbindutle ane�glanatlon q[he resulting lnvesbneM iNecnon
ledher NM or a tmdidonal imertmenN i—dilg the—and ranking of the
wlulion antl the aderiau-torankoreliminate—
N a NPA b—.tatted and—reawn k insurficien[impl—n—ir,
time,it ft.ld induee steps the Company will take b perbml NPA
nalyeiz m vmNae:InXdem impbmenrahpn Nme ror M1rtpre projrclz.
shouts inclutle tM1e rewlN of airttibution system planning,inclutling prapcl
data anld NM anatysis ror any proposed tratlbonal irxertmems,and NPA analysts br wry
prop NPA
a.FlR I-should1—di,ada[abase containing information about leetlerz,in service
dates W pipes,antl lowert recent oburved pressures.
2025 Natural Gas IRP Appendix gg 492

Oregon
Public Utility
Commission Attachment
2. Future distribution system planning should include an NPA framework in Oregon. The
framework should include:
d. NPA analysis should look forward five years to allow ample time for evaluation
and implementation.
e. NPA analysis will include an explanation of solutions considered and evaluated
including a description of the projected timeline and annual implementation rate
for the solutions evaluated, the technical feasibility of the solutions, and the
strategy to implement the solutions evaluated.
f. NPA analysis should include an explanation of the resulting investment selection
(either NPA or a traditional investment) including the costs and ranking of the Attachment
p5P Practices and IRP.messes to include:
solutions, and the criteria used to rank or eliminate them. °°lannmgahpnldidemNthe rationaleM1rpm;euaaedher
eliablliry,or Curtomer GroMM1/Reliability Related tp Grow[M1.
; th-tldven pmlec[s in I—the Mllty shoultl be prepared to
I.on:relanonihipto CPP compliance 1-M,,modeling and
i. If a NPA is not selected and the reason is insufficient implementation Iramework nen—ri,lotlbre�rt.andaessmempfalcernade=
.
n planning shpuld include an NPA fnmewmk in Oregon.The
time, it should include steps the Company will take to perform NPA ortermdosppplysitle reeourcesftIey—utlebtV
s upstream of AvisG'x tlirtribution system aM my
sitle contracts)and W disMbodon syrtem reiMorcemerds and
xceetl a--Id N%million for indMd..I prgects or
analysis to provide sufficient implementation time for future projects. '°`1P°° gr°°. °""`ha'
e "d"°'tt°'ea"
df.
dude cost berirHd analysrs that r0—ana Wo GHG
dement cones—wilha high-m e dfuture
races.Non-Energy Impacts must be�ncI—as part of the NPA
code electrifintion,Iari..energy effide drgrdea
antl°[her altematite mlutions.
iW look forwaA five years toallowample time for evalrration
I,ode an esplanatlon W mlueons c°nsiaeretl and evaluated
ption°f thep"] timeI—and annual implementation rate
ated,thetedrnical feavbiliN of the wludons,and the
tit the solutlons evaluated.
iM include an eaplanation of the resulting Invesbnent iNection
adidonal irnestment�i—ding the—and ranking of the
.-1, used[°rankoreliminate—
eaetl ane the reamn k insufficient implementa—
Wd incline rteps the cMo.Y will bke to perform NPA
nalysis to provitle suficient implementation dme brfuture pmjMs.
3.i Ps should inclutle the rewlts pf tlirtdbution syAem planning,inclutling prapcl
dataranld NPA analysis(or cent proposed VadNonal irwestmeres,antl NPA analys5lor arty
proposed NPA.
Future lRPs—.Id inclutle a database containing information about leetlerz,in service 4 tlates W pipes,antl lowert recent oburved pressures.
2025 Natural Gas IRP Appendix gg 493

Oregon
Public Utility
Commission Attachment
3. Future IRPs should include the results of distribution system planning, including project
data and NPA analysis for any proposed traditional investments, and NPA analysis for any
proposed NPA.
4. Future IRPs should include a database containing information about feeders, in service
dates of pipes, and lowest recent observed pressures.
Attachment C
The Company—ld upd-its p5P practices and I RP proc
t -button system esses to include:
IF—I-b planning should i id—fy the rationale for pmjecH as edM1er
Safery/Ge�reral System Rdiab.ift or Curtomer G—h/Reliability Related M Growth.
—proposing gmwM-0—projects m lRPS Me Mliry snoultl be prepared to
a p—project data on:reW—hipto CPPcompliance—M,,mo M.,and
venNed measuremem,lrcal load foremrt,and assessmem of alternatives
Mrvugh Me NPA famework.
i.F re dirtrlbution system planning snoultl inclutle an NPA framework in Oregon.The
ramework Mwm mdPae:
a.NManalKis will be performed for suppMsiae resources l[neu Wdude but are
of limitetl to all resourtes upstream of AWSG's tlirtribution syrtem aM my
gaces,ands ly id,mmracts)aM ror disbibutlon Nrtem reinforcements and
an pmjects[Mt eueed a M—h.W of%million ror i7dMtlual projects or
gmupslof g-,-ph,.IN related prgxts(a group of projects Mat are
terdepentlent or iMemelated).
b.N analKis will include cost bi,a —1al —reflects ana ide GHG
ompliance cart element cansi—..a M1igtl-wrt estimate of future
alternative fuels pdm.Non-Energy Impacts mart be in I—as part of Me NPA
analysis.
c. W:Zlnis will inclutle electrMotian,largeled energy egsdency,.R-d
demand response,ana abler altemative wlutions.
d.N analK 0n ld Wk t,waMfive years to allowamge time for evaluation
aM implemem t-
NPA analnls will inclutle an eaplanation of wlutions cansitlered and evaluated
nclMin¢a aesoiptian of the projected nmebne and annual implememanon rate
rortne wlutians evaluated.theceshnical feasibility of the wlutions,antl Me
rategy m imgement Me solutions eyawaee.
f. N analna snoam mdMe anewmnation orMeresuMn¢Inestmem selection
)edher NM or a tmdidonal imertmentj ii—dilg the—and ranking of Me
wlution antl the tide,!.u-to rank or eliminate Mem.
i.N a NPA.rot elected antl the reawn k insufficien[impl—nta—
time,it Mould indude steps the Company will take M perfmm NPA
nalysista prwiae sufidem implementation time rorfuture projMs.
3.F PM anaWlysrcis rore
db anldNA M1e rewlts ofMrtdbution syrtem planning,inclutling prapcl
proposed trMNonal invertmerrts,and NM analys5 ror airy
pro—NPA
a.Future IRP,Mould mdude a drt l—containing information about leetlerz,in service
dates of pipes,and lowert recent observed pressures.
2025 Natural Gas IRP Appendix gg 494

Thank you
Nick Sayen
Senior Utility Analyst
(503 ) 510-4355
nick.sayen @ puc. oregon .gov
Oregon
Public Utility
2025 Natural Gas IRP Appendix C o m q;p i o n

Targeted Load ManagementOvervie

Agenda
• What is TLM at Energy Trust?
• TLM Process Phases
• Program
es
• Prior TLM Examples-pt
a Medford and Sutherlin

What is TLM at Energy Trust?
A range ofplanning , and communit services :
9 Y
• Market intelligence and characterization
• Resource potential analysis
• Program design and delivery strategies
• Customer and community engagement
Objectives :
• Determine whether targeted energy efficiency can meet local
utility system needs
• Deliver benefits to utility and local communities

Targeted Load Management Process Phases
Identify Analyze Go/No-Go Build out
constrained resource TLIVI program decision with budgetand TLIVI
areas and utility potential (one planning and Energy Trust strategies for Implementation
needs or many sites) strategies and utility annual ETO
partner budget
`Could include funding beyond current PPC funds

Program Implementation Strategies
Previous TLM efforts included :
• Increased incentives : maximum based on cost effectiveness, and
max allowed based on localized avoided costs
• Increased Trade Ally (TA) engagement: training , participation
agreements, single point of contact support, incentive form
assistance
• Increased Trade Ally Business Development Funds : to
subsidize and support TA sponsored marketing efforts
• Increased Marketing : local newspapers, social media, tabling at
local events, TLM landing page
• Increased Customer outreach and engagement: proactive
contact with large commercial and industrial customers
2025 Natural Gas IRP Appendix 500
5

Avista TLM Analysis :
Medford and Sutherlin

Avesta TLM : Load Forecast Composition
Customer Segment Medford Sutherlin
Residential 62% 64%
Commercial 37% 25% \
Industrial 1 % 10%
• The load forecast and premise IDs identified in each TLM area are primarily
residential with some commercial and industrial.
➢ This load breakdown was used as input to the resource assessment model
2025 Natural Gas IRP Appendix 502
7

Avesta TLIVI : Total Potential and Program Activity
1W r
Area Utility Target Total Efficiency Historic Annual
Goal Resource Average
Medford 691 479 11
Sutherlin 121 158 2
peak hour therms
three-year total efficiency resource, cost-effective achievable potential
• Resource assessment modelling results demonstrate there is not enough
peak reduction to meet AVI load reduction targets.
➢ The Medford AVI target is 144% of resource potential. \
➢ The Sutherlin AVI target is 77% of resource potential.
• Program history shows the targets are 60x greater than a typical year of
8
program activity. 2025Na,ural Gas IRPAppendix 503 \

Thank you !
Adam Shick, Planning Manger
[e-mail]
Spencer Moersfelder, Director of Planning and Evaluation
spencer. moersfelder(aD-energytrust.orq
Willa Perlman, Planning Project Manager
willa. perlmanCa�-energytrust.orq
2025 Natural Gas IRP Appendix • 504
9

-IMA&MAL
Supplemental Slides
2025 Natural Gas IRP Appendix 505
10

Resource Assessment Overview
What resourcfassessment?
j L
• Estimate of energy efficiency resource potential at a range of costs that
is achievable over a defined number of years
• Identifies opportunities for energy efficiency measures within a territory
based on existing conditions of building stock
LU JV;**M
• The purpose is to help Energy Trust and utilities strategically plan future
investments in both demand side and supply side resources
• Provides acost-effective resource estimate of annual and peak savings
• For localized efforts, it helps inform a go/no-go decision
Is the locational potential enough.AGsmaet utility targets? 506
11

Avista TLIVI : Forecast Using NWN Pilot Results
Area Utility Target Pilot Total Resource Pilot Historical
Goal Results Results
Medford 691 66 63
Sutherlin 121 18 12
peak hour therms
assumes three-year TLM project
29 years needed to achieve targets at NWN pilot rate
• NWN Pilot achieved 4% of resource potential in two years of enhanced
incentives.
➢ Generalizing to a three-year project this equates to roughly 12% of Avista's targets.
• NWN Pilot nearly doubled historical acquisition .
12 ➢ This would result in about 9% ofAvista'S°Zt9fWd6tsPi�4e� three-year period. 507

Past TLM Example : Gas efficiency measure mix
Wall insulation 3 (2.68%)
Ceiling insulation 9 (8.04%')
Gas furnace 17 (15.18%)
.„e,mo:,,, so 535 ,,
2025 Natural Gas 508
13

Past TLM examples : Marketingmaterialsp \
TLM Commercial Postcard
TLM Residential bell Insert
I
INCREASED INCENTIVES \
FOR HOME UPGRADES
UPGRADE YOUR HOME FOR LESS \
Energy Trust of Oregon and NW Natural are working y
■
to ether to offer increased incentives and savings
\
g g \
on energy-efficient upgrades for homes in your area.
From gas furnaces,to insulation,to smart thermostats
and more we've you of covered. f \
g Y � \
MAKE EVERY DOLLAR COUNT
NW Natural' EnergyTilWITH LIMITED-TIME Entil-gyTil
Vlt4o� \
of or•ao�
BONUS \
HELP YOUR BUSINESS \E OV 3 E5s SAVE
_= MORE COMFORT,MORE SAVINGS h..p � .71l
limited-time i «rlt•«M JW/«,w.rlrnr/•.,.M/1,r�wr M r. rM.
As a NW Natural customer,enjoy these exclusive incentives •�.n/.•�^ yu wr•«Ir ..r...... �� �� \
OC, Energy Trust:from Ener �•rr MNw.ww rwa \
I�.Iw/l1•I w7•/ \
r•IrNr11r..MW Md./a .a.r• rn Mr.«MrM/.11 \
s_=- High-efficiency — rr.ldurr[M.•rr...r1M.r.r,J�/irr n«•M 11r«./..IAW \
natural gas furnaces $1,000 \
® •High-efficiency natural as fireplaces—up to$250 \
g g
•Insulation—up to$1.25persq.ft r., ,w,,,,yw,,,�„�•o,l,,,,l,,,v[o,,,«Il,,,,o, \
•Windows—u to fL \
1 P $8 Per 5q. •i,-�.•.,r.n..l... •.L�.•.. •u_,Jr.•.,
r, •IIVh rrl..4•Ir•r«r.,.r,.Irl.•.., \
For even more savings,we're also offering$100 off qualifying smart
thermostats which let you control our comfort from anywhere. \
• Y Y Y
f \
1
HI 1nY 1e •i,V1•NI
T
Visit www.ener trust.or /nwnatural romo to et started. .••
gY S P g
O
Incentives are subject to funding availability and may charge.Some qualifications apply
\1 /u 9 Y Y 9 9 (
MW N•1Y1.1
2025 Natural Gas IRP Appendix 509
14

Analyze resource Develop program Go/No-Go Build out budget
Phase/ Identify constrained potential (one or planning and decision with and strategies for TLM
Aspect areas and utility needs many sites) annual ETO budget strategies to meet Energy Trust and Implementation
localized needs utility partner
Collaborates with utility Use existing suite of
4_0Use Resource measures/offers
i partner to understand Assessment (RA) mapped to each TLM Owns the program Lead all aspects of
various utility needs delivery strategy implementation for
> Model to estimate area need; Consider
(e.g., potential in local local community and implementation EE and distributed
W peak demand, flexible plan RE (for electrics)
load, carbon) areas needs for design and Joint decision
delivery needed for Energy
Provides data on Trust's budget
Analyzes grid needs Collaborate on cycle Collaborate in key
a, specific feeder(s) Y Agrees to overall
= and grid constraints, Distributed Energy areas — regional
M typically through IRP and any market Resources play through 1) account
0. (historical) and new verticals; (DERs) beyond EE, overall budget management/
Provides localized process, ) any
processes like DSP or avoided costs including DR/flex load, additional funding outreach, CBAIGs,
CEP storage, EVs marketing
estimates
Potential to further Consider ETO Demonstrate input
automate early analysis Consider how both
Neighborhood via existing
with feeder data and To network Energy Trust and Share insights of
RA model; Reports and/or channels:
with community utilities represent "how this is
� Market ,
Establish project leads partners early and insights from Advisory Councils impacting
c Characterization outreach/
v with decision-making 4K "
Reports at this 20 aural Gas IRP Appen ix community community comrp ynities
authority at each engagements
..+r1.+., stage networks

Additional Program Delivery Strategies
• Fixed Price
ons
• Communityl
Funding (CPF) promotions 'if..low-.
�„ \
• Community Based Organization (CBO)
AftV
engagement
• Income qualified offers � � \
• No-cost offerings (incentive covers full cost of � .
measure)
• install and pays full os Direct tall offerins :g
Eof measure
coordinates
• Introduction of new measures such as : duct
sealing and duct insulation V%k

VISTA&
Weather
Avista 2025 IRP
TAC 5 — June 5t", 2024

Weather Forecasts
Data by Planning Region MACA 4.5 data'
• Klamath Falls Multivariate Ada tive Constructed
Analogs (MACH
• La Grande • Median HDD values of available
studies by planning region
• Medford - HDD calculated from Average of Min/Max
by study
• Roseburg
• Trended HDDs from 2026 — 2045
• Spokane Rollinq 20-year blend (historic and
MACA HDDs
2025 Natural Gas IRP Appendix 513
2
1 MACA Statistical Downscalinq Method (northwestknowl edge.net) �iI VISTA®

MACA versus Actual Weather
(Spokane)
Weather Comparison 2020 - 2023 Comparison
10,000 7,400
9,000 7,200
7,000
�
!� 6,800 ------------- -----
8,000 �` h
7,000 ��'% v� 0 6,600
= 6,400 ---- s• ----•
N 6,000 6,200
p 5,000 6,000
4,000 5,800
3,000
5,600 2020 2021 2022 2023
MACA History
4.5 Median 6,477 6,471 6,416 6,288
2,000 4.5 Average-8.5 Average 8.5 Median 6,431 6,535 6,361 6,213
1,000 Rolling 20 year (HDD) Actual History 6,766 6,609 7,276 6,569
0 --- Actual History --F Average 4.5 6,413 6,413 6,413 6,413
O Iq 00 N w O Iq 00 N w O Iq 00 N CO CD q* 00 N CO II III I O � 00 N CD O -- Average 8.5 6,385 6,385 6,385 6,385
LO LO LO (0 t0 r• ll- r` 00 00 oA oA oA O O r r (N N M M CM � Iq LO
0) a) 0) a) 0) a) a) 0) a) 0) 0) a) N N N N N N N N N N N N N --- Average History, 6,805 6,805 6,805 6,805
2025 Natural Gas IRP Appendix 514
3 �°Iw�sra®

Weather History Comparison
10,000
■2004 ■2023 ♦Max of 20 Years
9,000 8,339
8,000 ♦ 7,562 7,627
7,000
6,000 5,434 5,142
0
p 5,000
4,000 •
3,000 •
2,000
1 ,000
Klamath Falls La Grande Medford Roseburg Spokane
2025 Natural Gas IRP Appendix 515
4 'ed°I7 Irmsra®

Klamath Falls
Weather History and 4. 5 MACA
10,000 10,000 70
9,000 9,000 °
8,000 8,000 60 COR: 72
7,000 7,000 — U so
6,000 6,000 0
0 5,000 0 5,000 * ao
= 4,000 = 4,000 1 . 15% reduction in HDDs 30
3,000 3,000
2,000 2,000 zo
,000 —Rolling 20 year(HDD) 1 000 MACA Annual 10
—Actual Annual HDD ......•••Linear(MACA Annual)
O 00 N CO O 00 N �0 O 00 N f.0 O 00 N _
Lill
0 0 M w w ti I,. h w w O M M O O � r � N tD f� CO 0 CDr N PM V 0 O ti W M CD T- N M V 0 0
O Of O O O O O 0M O O C1 0) O O O O O O N N N N M M M M M M M M M M V V V V V o N a <o ao o N a <c o o
r r r . . r N N N N N N O CD CD CD CD CD CD O O O O O O O O O O CD
N N N N N N N N N N N N N N N N N N N N
Weather History 4.5 MACA Peak HDDs
20 Year rolling HDD daily Trended reduction in HDDs Coldest on Record Dates:
average of 7,695 HDDs from 2026 to 2045 12/21/1990
(2004-2023) 12/8/2013
1/6/2017
2025 Natural Gas IRP Appendix 516
5 'ed°I7 Irmsra®

La Grande
Weather History and 4. 5 MACA
10,000 10,000 0 45
9,000 9,000 = 40 COR: 75
8,000 8,000 M
m
35
7,000 7,000 0
y 30
6,000 ,� 6,000 0
p 5,000 p 5,000 25
= 4,000 = 4,000 20
3,000 —Rolling 20 year(HDD) 3,000 2, 13% reduction in HDDs 15
2,000,000 —Actual Annual HDD 2,000 MACA Annual 10
••••••••Linear(MACA Annual) 5
0 -
O O N t0 O It CO N O O Iq CO N to O CO N to I- CO M Q r, N M IV LO O ti CO CA O r N M VW
U) Ln LO to O I,- ti I` 00 CO O O O O O r r r N N N N N M M M CO) M CO) M CV) CO) CO) qe V V V qe q O
O O O O O O O O O O O O O 0 0 0 0 0 0 00000000000000000000 O N v to a0 O N v O ao o N V O DD O N
r r r r r r r r r r r r r N N N N N N N N N N N N N N N N N N N N N N N N N N O Ln an O Ln to Lo to to O r r r r r oo O
Weather History 4.5 MACA Peak HDDS,
20 Year rolling HDD daily Trended reduction in HDDs Coldest on Record Dates:
average of 6,978 HDDs from 2026 to 2045 1 /31 /1996
(2004-2023)
2025 Natural Gas IRP Appendix 517
6 'ed°Ih ormsra®

Medford
Weather History and 4. 5 MACA
10,000 10,000 0 9
9,000 9,000 8 COR: 61
8,000 8,00000
7,000 7,000 CU
0
rn 6,000 rn 6,000 0 6
000 5
o p 5,000 s, — S
= 4,000 = 4,000 4
3,000 3,000 2.14% reduction in HDDs
3
2,000
Rolling 20 year(HDD) 2,000 MACA Annual 2
1,000 1 000
0 —Actual Annual HDD , _ ......•••Linear MACA Annual) 1
O CO N O O le 00 N O O le CO N O O le CO N CO 1-- 00MOrNMleW) COt� 00MQT" NMIqLO i i i III IR LO LO LO O O ti ti ti 00 00 O O O O O � � � N NNNNMMMMCMMeMMMMqeqe V qeIqq 0
CA CA CA CA CA CA CA CA 0) 0) 0) 0) 0) 0 CD CD CD CD CD00000000000000000000
r r r r r r N N N N N N NW) LOw rnnn CON N N N N N N N N N N N N N N N N N N N 0 N w w w w 1- CO
Weather History 4.5 MACA Peak HDDF,
20 Year rolling HDD daily Trended reduction in HDDs Coldest on Record Dates:
average of 4,965 HDDs from 2026 to 2045 12/9/1972
(2004-2023)
2025 Natural Gas IRP Appendix 518
7 'ed,11hormsma

Roseburg
Weather History and 4. 5 MACA
10,000 10,000 0 3.5
9,000 9,000 °_ CO R: 55
8,000 8,000 f6 3
7,000 7,000 0 2.5
rn 6,000 y 6,000 0
p 5,000 p 5,000 2
= 4,000 = 4,000
0 1.5
3,000 3,000
3.35 /o reduction in HDDs
2,000 2,000 1
1,000 —Rolling 20 year(HDD) 1 000 MACA Annual
_ —Actual Annual HDD ......•••Linear ftCA Annual 0.5
0 M> 0 W W 1- 11� 1- M M M M M O O r r r N
M M M M M M M M M M M M M 0 0 0 0 0 0 O O O O O O O O O O O O O O O O O O O O 0
r r r r r r r r r r r r r N N N N N N N N N N N N N N N N N N N N N N N N N N o N t0 a0 o N c0 00 o N t0 a0 o N
Weather History 4.5 MACA PeaK HDD:
20 Year rolling HDD daily Trended reduction in HDDs Coldest on Record Dates:
average of 4,627 HDDs from 2026 to 2045 12/22/1990
(2004-2023)
2025 Natural Gas IRP Appendix 519
8

Spokane
Weather History and 4. 5 MACA
10,000 10,000 0 Sao
9,000 9,000 @ 120 CO R: 82
8,000 8,000 T
7,000 7,000 0100 '
0
0 6,000 6,000 80
G 5,000 0 5,000 '
= 4,000 = 4,000 3.56% reduction in HDDs 60
3,000 3,000 40
2,000 —Rolling 20 year(HDD) 2,000
MACA Annual 20 II I
1,000 —Actual Annual HDD 1,000 ...Linear(MACA Annual)
OIT 00 N to O11 00 N OO V W N OO V w N totiM (3) OrNMIttotGtiOtrOrNMItto o N a CO CO O N a CO 00 o N It (0 00 o N
t0 t0 f� f� f� t70 w O O O O O r r r N N N N (14 M M M M M M M M M M 111'* It ItI'* It W) u) W) N N to m CO CO w 1n r n I- r CO W
to to O O O O O O O O 0) 0) 0) 0 O O O O O 0 0 0 0 0 0 0 O O O O O O O O O O O O O
r r r r r r r r r r r r . N N N N N N N N N N N N N N N N N N N N N N N N N N
Weather History 4.5 MACA Peak HDDF
20 Year rolling HDD daily Trended reduction in HDDs Coldest on Record Dates:
average of 6,946 HDDs from 2026 to 2045 12/30/1968
(2004-2023)
2025 Natural Gas IRP Appendix 520
9 'ed,71hr sra®

Peak Day Options
99% Probability Coldest on Record (COR) COR less decrease in HDDs
Weather futures are Some coldest on Uses a coldest on
higher than coldest record temps have record less the
on record and not occurred in average decrease in
drasticallyincreases g
recent history temps from 2026 -
the peak day for
each area 2045
Max daily temp
across all weather
futures
2025 Natural Gas IRP Appendix 521
10 �i'lh�FST'a

Klamath Falls
25
—'51/'52'80/:81 Reference Period
—'01/'02=23/24 Period
8500 80
20
8000 78
76
w 7500 p a 15%
o C1 74
7000CU Y
72 LL 10 i
c d
Q 6500 70 —COR less avg.weather decrease
6000 Min/Max(1950-2023) —4.5 68 —coldest on record 5%
=8.5 —Historic Actual 66 99/o probability of future
Rolling 20-4.5 —Rolling 20 year(HDD) C�O r oo rn O N CO �t LO co �_ 00 rn O N M LO
551 N N N N M M M M M M M M M M I It 't It It 0%
LO I- a>� M In h O � M In I� O � M LO I- O)� M LO I- O � M LO 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O LO O LO O LO O LO O Lq O Lq O Lq O Lq O Lq O Lq O
O O O o 0 0 o O 0 0 0 0 0 N N N N N M M M M M o 7 V N N N N N N N N N N N N N N N N N N N N
O O O O O O O O O O O O O O O 000 O O O o 0 0 00 V n 7 7 M M (V N O o O N N M M 7 7 n
N N N N N N N N N N N N N N N N N N N N N N N '
Z-Stat
4.5 MACA Peak Historic Weather Comparison
• 4.5 Median of future weather Coldest on Record less average 1951 — 1981 Winters (Dec, Jan, Feb)
studies forecasted annual decrease
(2026-2045) Compared to:
• 20 year rolling average 2025 IRP: 71 HDD peak 2001 — 2023 Winters (Dec, Jan, Feb)
(historic + forecast) planning
(89% probability in MACA 4.5)
2025 Natural Gas IRP Appendix 522

La Grande
30%
—'5152'80/'81 Reference Period
8500 90 /'02'23/'24 Period
25
8000
7500 85
20
0 7000 80
� 0 U
_ ID 15%
6500 Y
m 75
Q 6000 CL
—COR less avg.weather decrease 10%
5500 70
—coldest on record
5000 Min/Max(1950-2023) —4.5 —99%probability of future 5%
—8.5 —Historic Actual 65
4500 —Rolling 20-4.5 —Rolling 20 year(HDD) co r- oo o> o N M v u,) co r- oo o� o N M v Lo
n r 0) M n I�d) M n rn CO Ln h O M u�r rn M N N N N M M M M M M M M M M
0,O O o 0 0 0 0 N N N N N M M M M M V V 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
rnrnrno0oo000000000000000000o NNNNNNNNNNNNNNNNNNNN 0%
N N N N N N N N N N N N N N N N N N N N N N N O LA O N O LO O N O U O U� O U O U O Lq O Lr� O
Z-Stat
4.5 MACA Peak Historic Weather Comparison
• 4.5 Median of future Coldest on Record less average 1951 — 1981 Winters (Dec, Jan, Feb)
weather studies forecasted annual decrease
Compared to:
(2026-2045)
• 20 year rolling average 2025 IRP: 73 HDD peak 2001 — 2023 Winters (Dec, Jan, Feb)
(historic + forecast) planning
(69.5% probability in MACA 4.5)
2025 Natural Gas IRP Appendix 523
12

Medford
25%
—'51/'52'80/'81 Reference Period
7500 65
—'01/'02-'23/'24 Period
7000
20%
6500
y 6000 0 60
15%
5500 =
Y �
5000 a) LL
°
4500 a- 55 —COR less avg.weather decrease °
4000 —coldest on record
Min/Max(1950-2023) —4.5 5%
3500 —8.5 —Historic Actual —99% probability of future
3000 —Rolling 20-4.5 —Rolling 20 year(HDD) 50
u')r` 0) Mu'>r`M — Mu' ;� M0I_ M MLOI­ rn � M0 G4 ti 00 M O N M 'ITLO CO t` 00 M O � N M � LO
CD o o N N N N M MMMo CD - - - -� N M M M M V 7 V N N N N M M CO M M M M M M M I Nt 't � �t 0% A .
rn rn rn o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o O O O O O O O O O O O O O O O O O O O O o o n o n o u o n o n o u o n o n o o
N N N N N N N N N N N N N N N N N N N N N N N U+ I+j (V N O O O
Z-Stat
4.5 MACA Peak Historic Weather Comparison
• 4.5 Median of future weather Coldest on Record less average 1951 - 1981 Winters (Dec, Jan, Feb)
studies forecasted annual decrease
Compared to:
(2026-2045)
• 20 year rolling average 2025 IRP: 60 HDD peak 2001 - 2023 Winters (Dec, Jan, Feb)
(historic + forecast) planning
(96% probability in MACA 4.5)
2025 Natural Gas IRP Appendix 524
13

Roseburg
30%
6500 —'51P52-'80/'81 Reference Period
65 —'01P02--23/'24 Period
25%
6000
5500 60 20%
o p
U
5000 2
Y 55 15%
4500 N
a_ i
4000 50 —COR less avg.weather decrease 10%
—coldest on record
3500 Min/Max(1950-2023) —4.5 —99%probability of future 5%
—8.5 —Historic Actual 45
3000 —Rolling 20-4.5 —Rolling 20 year(HDD) N N N N M M M M M M CO M M M V V V � � �
�n rn M uO h 01 M v� n rn M uO r rn M u, n rn M LO 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0%
rn rn m o 0 0 0 0 N N N N N M pM M M M V V V N N N N N N N N N N N N N N N N N N N N
rn rn rn o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 �n o u� o Un o u> o Ln o Un o Ln 0 Ln o , 0 �n o
N N N N N N N N N N N N N N N N N N N N N N N I? cy N N O O O — — N N M M V 7 In
Z-Stat
4.5 MACA Peak Historic Weather Comparison
• 4.5 Median of future weather Coldest on Record less average 1951 — 1981 Winters (Dec, Jan, Feb)
studies forecasted annual decrease
Compared to:
(2026-2045)
• 20 year rolling average 2025 IRP: 53 HDD peak 2001 — 2023 Winters (Dec, Jan, Feb)
(historic + forecast) planning
(75.5% probability in 4.5 MACA)
2025 Natural Gas IRP Appendix 525
14

Spokane
9000 30%
100 —'51P5280181 Reference Period
8500 —'01P02-'23/'24 Period
25%
8000 80
p 7500 20%
0 60
7000 =
m 15%
Q 6500 40 _COR less avg.weather decrease 10%
6000
Min/Max(1950-2023) —4.5 20 —coldest on record
5500 —8.5 —Historic Actual
—Rolling 20-4.5 —Rolling 20 year(HDD) —99% probability of future 5�
5000
M r` W CO LO r` W P M � � �� M � � a1� M rn r d1� M �
rn rn rn o 0 0 0 0 r r N N N N N M M M M M v v v N N N N CO M M M M M M M M M 0%
rn rn rn o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o n o n o n o n o n o n o u� o n o n o n o
N N N N N N N N N NN N N N NN N N N N N N N N N N N N N N N N N N N N N N N N N N N ui a s C6 vi N CV o o c N N M M a l LO
Z-Stat
4.5 MACA Peak Historic Weather Comparison
• 4.5 Median of future weather Coldest on Record less average 1951 — 1981 Winters (Dec, Jan, Feb)
studies forecasted annual decrease
Compared to:
(2026-2045)
• 20 year rolling average 2025 IRP: 79 HDD peak 2001 — 2023 Winters (Dec, Jan, Feb)
(historic + forecast) planning
(80% probability in MACA 4.5)
2025 Natural Gas IRP Appendix 526
* �IIII��STa®
15 Weather used for Idaho and Washington

Summary
• MACA 4.5 weather median futures trended from 2026 — 2045
by planning area and combine with historical actual data into
a rolling 20-year average
• Peak Planning : coldest on record less average decrease in
H D Ds from 2026 - 2045
2025 Natural Gas IRP Appendix 527
16 'edi Insra®

EBV� w
I
2025 Natural Gas Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Wednesday, June 26, 2024
Virtual Meeting
Topic Time (PTZ) Staff
Feedback from prior TAC 10:30 All
Current Avista Resources 10:40 Justin Dorr
Greenhouse Gas Emissions & Pricing 11 :15 Tom Pardee
TAC feedback 11 :50 All
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 285 938 629 442
Passcode: 8TysAy
Download Teams I Join on the web
Or call in (audio only)
[phone]„325846108# United States, Spokane
Phone Conference ID: 325 846 108#
Find a local number I Reset PIN
Learn More I Meeting options
2025 Natural Gas IRP Appendix 528

►�OirIstA
Supply Side Resources
Justin Dorr
Manager of Natural Gas Resources

Interstate Pipeline Resources
• The Integrated Resource Plan (IRP) brings together the various components
necessary to ensure proper resource planning for reliable service to utility
customers.
• One of the key components for natural gas service is interstate pipeline
transportation. Low prices, firm supply and storage resources
are meaningless to a utility customer without the ability to transport the gas
reliably during cold weather events.
• Acquiring firm interstate pipeline transportation provides the most reliable
delivery of supply.
2025 Natural Gas IRP Appendix 530
2 dill'VESTA

Pipeline Contracting
Simply stated: The right to move (transport) a
specified amount of gas from Point A to Point B
0 1 0
2025 Natural Gas IRP Appendix 531
3 eduVISTA

Contract Types
• Firm transport
Point A to Point B
Kingsgate to Malin
• Alternate firm
Point C to Point D
Kingsgate to Stanfield
• Seasonal firm
Point A to Point B but only in winter
• Interruptible
Maybe it flows, maybe it doesn't
2025 Natural Gas IRP Appendix 532
4 �iIVISTA

Pipeline Rate Design
• Mileage Rate (GTN )
Distance between receipt and delivery determines price
Plus variable charges (variable, fuel , commodity)
• Postage Stamp ( NWP)
1 mile from receipt to deliver same price as 1000 miles
Plus variable charges (variable, fuel , commodity)
2025 Natural Gas IRP Appendix 533
d,u�VISTA

Pipeline Overview
West Coss
Still
Empress
■ -O
or. a Hub
NW Sumas ate
�i
Stan Ald OR
1
CIG Rocky
Mou n to 111S
NoCal Border
Malin
NW Opal WV
Cheyenne
_ ern OuesLir Hub
R i V e-r .
White
River Hub
PG&E
Gate
m N of
Green ver NW Dorn
SJ Basin
2025 Natural Gas IRP Appendix El Paso 534
6 San Juan El Paso ��I�_
�/
Bondad eu� ISTA

Avista's Transportation Contract Portfolio
Avista holds firm transportation capacity on 6 interstate pipelines:
Pipeline Expirations Base Capacity Dth Current Rate
Williams NWP 2025-2042 285,000 $0.3725/MMBtu
Westcoast 2026 101000 $0.5770/ GJ
(Spectra)
TC- NGTL 2025-2046 146,500 $0. 1994/ GJ
i
TC- Foothills 2025-2046 144,300 $0.1448/GJ
TC- GTN 2025-2035 1427000-96,000 $0.0004297/Mile
TC- Tuscarora 2026 200 $0.23064/M M Btu
*1 MMBTU = 1.055056 GJ
1) Pipe reservations and modeling are only fQr2Q9,em�,WMars 535
7 2) Pipe reservations and model explicitly DO NOT CONSIDER electric side of business. eilVISTA

Northwest System - Strategically Located
1 SLLR1aS
Low-cost, primary service provider in �* ��
the Pacific Northwest `'�
Pt
0
3,900-mile system with 3.8 Bcf/d peak design
capacity tanflrld
• --120 Bcf of access to storage along pipeline,
with high injection and deliverability capability s�`~
in market area
Bi-directional design
Provides flexibility (Rockies to market and N,a,ta
Sumas to market) <<``I~
Cheapest supply drives flow patterns
a'a Gt
• Provides operational efficiencies through Wy displacement ""`
Supply and market flexibility ti llte Roer limb
65 receipt points totaling 11 .6 Bcf/d of
supply from Rockies. Sumas. WCSB. San SocalCG
Juan, emerging shales P Boodad
• 366 delivery points totaling 9.7 Bcf/d of EP Blanco
delivery capacity ` t Topork
t
2025 Natural Gas IRP Appendix AN 536
�Ilw�sra

■
GTN Overview '
NGTL System i
• Transports WCSB* and Rox natural AB/BC Border
as to I D WA O R and CA
g Foothills BC System ,
GTE Kingsgate
• Approximately 1 ,377 miles of pipe Stanfield
• Kingsgate best efforts receipt Tuscarora Malin
capability of approx. 2.87 Bcfd and •'
throughput capacity of approx. 2
Bcfd through Station 14. UNITED STATES
�� TC Energy
2025 Natural Gas IRP Appendix 537
*WCSB — Western Canadian Sedimentary Basin edill-VISTA

WCSB gas is competitive in key markets
WCSB (78% TC Energy)
18 Bcf/d supply
8 Bcf/d intra basin load
10 Bcf/d export CANADA
2 Bcf/d LNG projected by 2026
4 Bcf/d LNG projected post 2030
U.S. Northeast
7 Bcf/d market
0.7 Bcf/d via TC
Pacific 53%
9 Bcf/d market 11%
2.5 Bcf/d via TC 29`Yo
UNITED STATES Eastern Canada
12% 4.4 Bcf/d market
r 2.3 Bcf/d from WCSB via TC
Chicago (Mid-West)
13 Bcf/d end use market
FOR DISCUSSION PURPOSES ONLY I APRIL 2024 1.5 Bcf/d from WkISB-a�931TFGppendix TC Ervergy
Flow data based on 2023 Calendar year

Storage — A Valuable Asset
• Peaking resource
• Improves reliability
• Enables capture of price spreads between time periods
• Enables efficient counter cyclical utilization of transportation (i .e. , summer
injections)
• May require transportation to service territory
• In-service territory storage offers most flexibility
2025 Natural Gas IRP Appendix 539
d,u1VISTA

Avista's Storage Resources
Washington and Idaho
Owned Jackson Prairie
• 7.7 Million Dth of Capacity with approximately 346,000 Dth/d of
deliverability
Oregon
Owned Jackson Prairie
• 823,000 Dth of Capacity with approximately 52,000 Dth/d of deliverability
Leased Jackson Prairie
• 95,565 Dth of Capacity with approximately 2 ,654 Dth/d of deliverability
2025 Natural Gas IRP Appendix 540
12 ediI'VESTA

The Facility -
a- h
/ "k,proceeds
y "Wilt.
rbed
-- _ arlll&nests hiflg "-"
abnur tlx•xtivag• t
Jackson Prairie is a series of Jackson
rairle gas ���
storage field
deep underground reservoirs ihv le nectth 3.E(ID , A t y 1
7 MK'.111(load,tllll its n � /�
IInINe�lalllxl
basically thick, porous sandstone Gxi6liesrc+,nire
just nsr acres.
deposits.
The sand layers lie approximately
sedfinenr,
1 000 to 3 000 feet below the Gas Storage It,,.dafldY
1 7 fall
7.on<I l miltxlnm ul
ground surface. "PS
Ir8 the
Ilrlc ergnxttxt -
Large compressors and pipelines -1000'Sea T_
are employed to both inject and --- - - ---
withdraw natural gas at 54 wells _ -- �� Underground
spread across the 3 200-acre water_
p atajr'an I x'aisl he
facility. Gas is siomd eI Y'f the 11Ufa(,r
r- ?WIII feet cksgr ul ferL
pranln sandvow
a prellwarir srat~rl
boded In'xdunern
~ mxW(ram anc-irnt
nlcwrnaflti
Storage ..
Water
R 541
13 eduVISTA`

Jackson Prairie Energy Comparisons
1 .2 Bcf per day (energy equivalent)
10 coal trains with 100 - 50 ton cars each
29 - 500 MW gas-fired power plants
13 Hanford-sized nuclear power plants
2 Grand Coulee-sized hydro plants (biggest in US)
45 Bcf of stored gas
12" pipeline 11 ,000,000 miles long (226,000 miles to the moon)
1 ,400 Safeco Fields (Baseball Stadiums)
Average flow of the Columbia River for 2 days
Cube - 3,550 feet on a side
2025 Natural Gas IRP Appendix 542
14 �uVISTA

s uri'ISTA
Green House Gas Assumptions
and Climate Pricing
2025 Avista Gas IRP

Greenhouse Gas Assumpt 'ions
2025 Natural Gas IRP Appendix 544
2 dill-VISTA

CH4 emissions (kt) for Natural Gas Systems ( EIA)
100%
35
120 90%
M 30 80%
K
100 = 70%
T U 25
60%
a 80 20 50%
L a E 40%
p 60 °
o 3 15 30%
c 40 0 10 20%
20 —Daily Production-Dth O t 0%
U 5 0%
Or NM.v LOW f�0000gC4Cn v W)w f-0001
0 0 0 0 0rN M�IlY<Oh0000 r
_ 01 0 01 0 01 0 01 Of 01 Of 00000 r r r r r r r r r N N
Or NM V�rn�Corn Or NM V won cnrnor NM V No�oDrno o�NMvin�O�oCrno�NMyu><onCCmo�N Myin�o�rom o� ����������0000000000000000000000
rn rn rn rn rn rn rn rn rn rn o 0 0 0 0 0 0 0 0 o r N N m rn rn rn rn rn rn rn m rn o 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N N N N N
rnrnrnrnrnrnrnrnrnrnN0 N0 0N N0 CO 00000000000000000
N N N N N N N N N N N N N N N NN mrnmrnrnrnrnrnmrnoN oN oN oN oN 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N 0N oN Exploration ■Production■Gas Processing Plants Transmission and Storage
■Distribution ■Other
Production CO2e of CH4 per Dth CH4 by Major Category
Source: 2023 ghgi annex tables — EIA- Table 3.6-1 : CH4 Emissions (kt) for Natural Gas Systems, by Segment
and Source, for All Years
2025 Natural Gas IRP Appendix 545
3 �l'Il�r�sra

Total Emissions for natural gas
(combustion , upstream and LDC)
Fuel Emission Rates in
Ibs GHG per unit of natural gas combusted Ib GHG/mmbtu Ib CO2e/mmbtu
in Ibs & CO2e Ibs - 100 year GWP
Combustion
CO2 116.88 116.88
CH4 0.0022 0.0748
N2O 0.0022 0.6556
Total Combustion 118
Upstream
CH4 0.422 14.35
Total 132
*NWPCC — 2021 Power Plan with updated average actual AydgpW,5W,pigogses for prior 5 years 546
4 **Includes LDC L&U estimate of 0.8% �u VISTA

Use of Upstream Emissions in 2025 IRP
Evaluation of SCC scenario in all CCA and CPP do
energy efficiency in jurisdictions not account for
OR and WA upstream emissions
in program
requirements
2025 Natural Gas IRP Appendix 547
5 edilVIsra

Climate Commitment Act (CCA) Cap
8.0% 80%
= 7.0 /0 7 0% —Cap Reduction 70% —CCA Cap
0
v 6.0% 60%
5.0% 50%
L
4.0% 40%
V 3.0% 2.6% 30%
cE
2.0% 1 .8% 20%
c
Q 1.0% 10%
0
0.0% 0 ° Co r� oo cn CD N M qq 0 Co r'- oo C) CD N M Iq 0
Co CN C4 M O r N M O Co I` 00 O O r N M N N N N N M M M M M M M M M M Iq � qe qe qe
N N N N M M M M M M M M M M qe V V V V V O O O O O O O O O O O O O O O O O O O O
O O O O O O O O O O O O O O O O O O O O N N N N N N N N N N N N N N N N N N N N
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 548
6 �IIIIV�STA

Climate Protection Plan (CPP) Cap
700,000 2.42%
U 600,000 p 2.40%
n 38%
500,000 � 2
U a�
2.36%
400,000 Q 2.34%
E 300,000 - 2.32%
w 200,000 2.30 /°
2.28%
Q100,000 2.26%
Q 2.24%
U') W rf- M 0 Or, N M �T U') W o0 0 0 N M I LA U) W 1- 00 a) 0 N M I U) CO f` 00 Cn 0 N M mt U)
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
*RAC Draft Rules — June `24 — Tables 2 & 4 *RAC Draft Rules — June `24 — Table 4
2025 Natural Gas IRP Appendix 549
7 'dAi v►sraa

Cimimate Proicoing
2025 Natural Gas IRP Appendix 550

Social Cost of Carbon (SCC) at 2 . 5%
$250
�SCGHG (2007$) -SCGHG (2022$) -SCGHG Nominal
• SCC @ 2.5% will be used for
$200 Energy Efficiency CPA in OR and
o WA
V $150
• SCC scenario will utilize SCC @
$100 2.5% as a resource selection
criteria and is added to the price of
0- $50 emissions to each Dth of natural
61% gas for all jurisdictions
$0
CO 1` 00 0) O N CO) 11 LO t0 1- 00 O O r N M 41 0
N N N N M M M M M M M M M M q* Iq I* le le I*
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Source: https://www.utc.wa.gov/regulated-industries/utilities/energy/conaecvatiar►;afldPrAeaerable-energy- 551
9
overview/clean-energy-transformation-act/social-cost-carbon �MISTA

Allowance Prices
CCA California - Quebec
$100 $45
N $90 $40 —Secondary Market Price
•••���. .........�
—Auction Reserve Price
O `
••• f�(
V $80 ■.•••••••••■•••••••••�■•••••••••■ $35 • CurrentAuaionSettlementPrice
$70 $30
$60 *
3 $50 $25 ,
$40 $29.92 $20
Q $30 $15
� $10
CO $10 floor settle ••• •• ceiling $5
Feb-23 May-23 Aug-23 Dec-23 Mar-24 Jun-24 $0
W OD V P P O O O O O O N N N N f7 M M M a a
N N N N N N N N N N N N N N N N N N
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
Auction 1 Auction 2Auction 3Auction 4Auction 5Auction 6 NNNNNNNNNNNNNNNNNNNN NNNNNNNNNNNNNNNNNNN
aaaaab � aab� aabaaabaaab � aab � aaa � c► aa � aaa �
*Nov. 3rd Announcement to pursue linkage to CA Cap and Trade Cap-and-Trade Program Data Dashboard I California Air Resources Board
2025 Natural Gas IRP Appendix 552
10 edi IVISTA

Allowance Price Estimate
Nominal Price per MTCO2e
$400
$350
$300
$250
$200
$150
_ -
- v = z
———— WO .................
$50 ......................................................................
$-
l0 r- 00 M O i N M Ln t.O r 00 Cr) O i N M Ln
N N N N rn rn M M M M M M M M 'T ' 'T
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Min Percentile: 25% Mean Median Percentile:95% Max
2025 Natural Gas IRP Appendix 553
/III
11 *300 stochastic 20-year draws AMISTA

Community Climate Investments (CPP)
$250.00 25%
° Max CCI %
$200.00 20%
c�
o
$150.00 ,? 15%
O
c
;_ $100.00 `� Z) 10%
O > U
Z � �
$50.00 U 5%
U
$ per CCI M
$_ 0%
LO (DI- 00090 NM4TU) w1" 00G90T- NMqTUA LOCDf` OOa) 0 NMq* LO (D l` 00a) 0 NMqcT lf7
N N N N N M M M M M M M M M M N N N N N M M M M M M M M M MqT q* q* q* Nt
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 554
12 RAC draft rules 6/18/2024 �°I41ST'a

Use of Pricing in 2025 Gas IRP
• SCC @ 2.5% will be used for Energy Efficiency CPA in OR and WA
SCC scenario will utilize SCC @ 2.5% as a resource selection criteria and is added
to the price of emissions to each Dth of natural gas
• CCA pricing for the allowance market will be used to evaluate program
compliance in Washington
All cases except SCC scenario
• CPP pricing will be used to evaluate the use of CCIs for program
compliance in Oregon (Most recent draft rules available at the time of
modeling)
All cases except SCC scenario
2025 Natural Gas IRP Appendix 555
13 ed°IFVISTA

CCA Summary
800,000 Nominal Price per MTCO2e
■ Allowances - For Compliance $350
700,000 ■ Allowances - To Auction
Q
U 600,000 $300
Q
U 500,000 $2so
°' $200
400,000 —
300,000 `� ------------------
LU
— — —ram '�'� a•
- ..............
100,000 $so =Ma"' "ate- . ............................................... ....
� n oo rn o ti ry m io ry In o .� ry m v �n
" ellry ry ry m m In m m m m m m In
tD O O O N M14t M to I- CO CA O N M 1* Ln 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N M M M M M M M M M M g It 11 1* 11
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Min Percentile:25% - - Mean Median Percentile:95% Max
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 556
14 AHMSta

CPP Summary*
$250.00
25%
$200.00 �° Max CCI
o 20%
D $150.00
15%
o
o $100.00 `� 10%
$50.00
U 5%
U
S per CCI x
$ Q%
'0 (Dr- 00C'� O NM � LO (Dr` 00C') O � NM 'It � � ACC I` oOC� O � NM � � COI` oOC� O � NM � �
N N N N NM M M M M M M M M M N N N N N M M M M M M M M M MIqr
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
700,000
U 600,000
500,000
U �
400,000
*2025 IRP values will be °
updated based on RAC Z aoo,000
process and changes w 200,000
CU
100,000
Q
NN (14 3m RMaP�3 MMMIT � � � IRT NT 557
15 N N N N N N N N N N N N N N N N N N N N N III/VISTA

File April 1 , 2025
Updated TAC Schedule
TAC 6: Wed. 17 July 2024: 10:30 am to 12:00 pm (PTZ)
-Feedback from prior TAC (10 min.)
-Load Forecast—AEG (80 min.)
TAC 7: Wed. 21 Aug. 2024: 10:30 am to 12:00 pm (PTZ)
-Feedback from prior TAC (10 min.)
-Natural Gas Market Overview and Price Forecast (40 min.)
-Avoided Costs Methodology (30 min.)
TAC 8: Wed. 25 Sept. 2024: 10:30 am to 12:00 pm (PTZ)
-Feedback from prior TAC (10 min.)
-Heat Pump COP (30 min.)
-Electrification (40 min.)
TAC 9: Wed. 30 Oct. 2024: 10:30 am to 12:00 pm (PTZ)
-Feedback from prior TAC (10 min.)
•NEI Study (30 min.)
-New Resource Options Costs and Assumptions (40 min.)
TAC 10: Wed. 18 Dec. 2024: 9:00 am to 12:00 pm (PTZ)
-All assumptions review (20 min.)
-Conservation Potential Assessment (AEG) (30 min.)
-Demand Response Potential Assessment (AEG) (20 min.)
-Conservation Potential Assessment (ETO) (30 min.)
-Scenario Results (20 min.)
-Scenario Risks (20 min.)
•PRS Overview of selections and risk (20 min.)
-Per Customer Costs by Scenario (10 min.)
-Cost per MTCO2e by Scenario 558
edu Ill ISTA

AEG
APPLIED ENERGY GROUP
Avista Energy
Natural Gas Forecasting
Prepared for Avista Energy TAC Meeting July 2024
Confidentiality—The information contained in this presentation is proprietary and confidential. Use of this infcrmatiori is l,mited to the intended recipient and its employees and may not be disclosed to third parr;es.

Background C)AEG has worked with Avista for multiple Conservation Potential Assessments going back to
(D 2010
As part of the CPA, AEG creates a baseline projection at the segments and end use level,
which provides granular insight changes in individual technology classes and populations
Now Avista is using AEG's LoadMAPTm end use model directly to inform its official load
-�0, forecast, including effects of state energy codes, potential electrification and market trends
in a clear and direct manner.
Applied Energy Group,Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 560

gInputsMaJ' or Modelin and Sources 0Q
Avista foundational data Survey data showing Technical data on end- State and Federal Market trends and
presence of equipment use equipment costs energy codes and effects
and energy standards
consumption
Avista power sales by schedule Avista: Residential customer Regional Technical Forum Washington State Energy Code RTF market baseline data
Current and forecasted survey conducted in 2013 workbooks Idaho Energy Code Annual Energy Outlook
customer counts NEEA: Residential and Northwest Power and Federal energy standards by purchase trends(in base year)
Retail price forecasts by class Commercial Building Stock Conservation Council's 2021 equipment class
Assessments(RBSA 2016 and Power Plan workbooks
CBSA 2019) US Department of Energy and
US Energy Information ENERGY STAR technical data
Administration: Residential, sheets
Commercial, and Energy Information
Manufacturing Energy Administration's Annual Energy
Consumption Surveys(RECS Outlook/National Energy
2020, CBECS 2018, and MECS Modeling System data files
2015)
Applied Energy Group, Inc. I appliedenergygroup.com 3
2025 Natural Gas IRP Appendix 561

Forecast Process
OMMINN F -
Market Characterization Run - Projection
Segmentation (AnnuaL)
End Use and TechnoLogy List 9 Customer Forecast
9 Purchase Decisions
WOMEN MEMNON
Residential Gas Projection By End Use
miueuaneoa 30.000.000
Water Applianctr, Residential Gas Intensity by End Use and Segment
1nalin9 3%0% 1.000 25.000.000 •space Heating
�iidai 12%
y
Secondary Heating
}Heating / 1ne.myH — •space Heenn6 20.000.000
2%
ScoMery Heanng
DIh15.000,000 •water Heatng
H 500 eWanrM«ting
10.000,000 •Appliances
200 — —■— —.Hncelu«oc.
5.000.000 •nisceuaneous
Space .9iryle Femiiy Muni Fe y obiie Horne ll-Single
Heating Femiiy riF-1, Heine
83% 2021 2023 2025 2027 2029 2031 2033 2035 2032 Me 2U1 20a3 2045
Applied Energy Group, Inc. I appliedenergygroup.com 4
2025 Natural Gas IRP Appendix 562

Existing vs New Buildin
Modeling tracks existing building stock
Example WA Residential Intensity Comparison
separately from new code-compliant
soo
buildings
goo
Buildings also undergo renovation at a rate 600 ■Space Heating
consistent with the DOE's National Energy Secondary Heating
Modeling System, converting them into code- 500 Water Heating
compliant structures therms/HH 400 Appliances
0
Presence of equipment in new buildings is 300 Miscellaneous
adjusted to comply with energy codes where 200
applicable 100
For example, all new residential structures are Existing New
assumed to use electric or dual-fuel heat
pumps for space heating, which dramatically
Lowers gas loads in new construction
Applied Energy Group, Inc. I appliedenergygroup.com 5
2025 Natural Gas IRP Appendix 563

System Total Load Forecast
WA + ID + OR, Excludes Transport 4D
All-Sector Natural Gas Projection By End Use A combination of electrification, building
45,000,000 codes, and natural efficiency cause overall
40,000,000 gas loads to decline by7% across the
forecast period
35,000,000
Washington has a much stronger downward
30,000,00o trend in isolation, offset by growth in Idaho
25,000,000
otn (see next slides)
20,000,000
Includes:
15,000,000
Projected heating degree days according to climate trends
10,000,000 in Avista's territory
Market efficiency impacts (such as customers installing HE
5,000,000 furnaces on their own), which are saving 42 million therms
in the forecast period compared to minimum codes &
standards
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2047
■ Industrial ■ Commercial ■ Residential
Applied Energy Group, Inc. I appliedenergygroup.com 6
2025 Natural Gas IRP Appendix 564

Washington Sector- Level Forecasts C)WA Residential declines 15.8% as residential space heat electrifies (or converts to dual-fuel
systems) either in natural equipment replacement cycles or to comply with state energy code
Commercial declines for the same reason, however the decline is steeper as commercial space
tends to turn over faster compared to residential spaces (and therefor is under pressure to
become code compliant when new occupants move in)
Industrial loads do not have the electrification opportunity that res and com space heating do
and are minimally affected by the code requirements. Loads are generally flat.
Residential Gas Projection By End Use Commercial Gas Projection By End Use Industrial Natural Gas Projection By End Use
14,000,000 9,000,000 350,000
12,000,000 ■Space Heating 8,000,000 300,000
7,000,000
10,000,000 Secondary Heating 250,000
6,000,000
8,000,000 ■Water Heating 5,000,000 ■Space Heating 200,000
■Space Heating
Dth Dth ■Water Heating Dth
6,000,000 4,000.000 150,000 ■Process
■Food Preparation
4,000,000
■Appliances 3,000,000 ■Miscellaneous ■Miscellaneous
100,000
■Miscellaneous 2,000,000
2,000,000 50,-0
1,000,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 m o 0 0 0 0 0 0 0 r�i m o 0 0 0 0 0 0 0
Applied Energy Group, Inc. appliedenergygroup.com 7
2025 Natural Gas IRP Appendix 565

Idaho Sector- Level Forecasts
• ID gas loads do not have the same downward pressure as WA.
• While building shells improve inefficiency as older stock is renovated, customer growth
continues to increase the use of natural gas in the forecast.
Residential Gas Projection By End Use Commercial Gas Projection By End Use Industrial Natural Gas Projection By End Use
7,000,000 4,500,000 300,000
6,000,000 ■Space Heating 4,000,000
250,000
3,500,000
5,000,000 Secondary Heating
3,000,000 200,000
4,000,000 2,500,000 ■Space Heating
Dth ■Water Heating Dth ■Water Heating Dth 150,000 ■space Heating
3,000,000 2,000,000 ■Process
■Food Preparation
■Appliances 1,500,000 100,000
2,000,000 ■Miscellaneous ■Miscellaneous
■Miscellaneous 1,000,000
1,000,000 50,000
sao,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Applied Energy Group, Inc. appliedenergygroup.com 8
2025 Natural Gas IRP Appendix 566

Oregon Sector- Level Forecasts C)• Oregon has relatively stable natural gas loads, as building stock improvements keep pace with
modest customer growth and lead to reductions in overall gas use
Residential Gas Projection By End Use Commercial Gas Projection By End Use Industrial Natural Gas Projection By End Use
6,000,000 4,000,000 70,000
5,000,000 ■Space Heating 3,500,000 60,000
3,000,000 50,000
4,000,000 Secondary Heating
2,500,000
■Space Heating 40,000
Dth 3,000,000 ■Water Heating Dth 2,000,000 ■Water Heating Dth ■Space Heating
■Food Preparation 30,000 ■Process
■Appliances 1,500,000
2,000,000 ■Miscellaneous 20,000 ■Miscellaneous
1,000,000
1,000,000 ■Miscellaneous
500,000 10,000
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 INN, M m"' m o 0 0 0 0 0 0 o N
Applied Energy Group, Inc. I appliedenergygroup.com 9
2025 Natural Gas IRP Appendix 567

Electrification Decision Modeling
Washington Residential Gas Heating Market Transformation
• Gas customers were modeled the same way as the electric market,with Space Heating Equipment stock
the option to replace existing gas space or water heating equipment with —
90% ■Air-Source Heat Pump(ENERGY
electric alternatives, using purchase decision logic copied from the US STAR 6.1)-Boiler
DOE's National Energy Modeling System. 80% ■Air-Source Heat Pump(ENERGY
70% STAR 6.1)-Furnace
i
• Conversion costs include the possibility of a panel upgrade and v 60% ■Dual-Fuel Heat Pump-AFUE 95%
associated labor.The model compares the lifetime cost of ownership 50%
■Dual-Fuel Heat Pump-AFUE 80%
including up front costs and associated lifetime fuel costs. 40%
0
• As data on customer electrification is not readily available*, 30% ■Gas Boiler
electrification purchases were seeded with a value'/4 that of dual-fuel 20%
■Gas Furnace
i
heat pump installations,which do have documented market shares for 10%
WA and ID. p 0%
O,y'1.oy�'O'1'' O'1'a Otis Otib Otis Oti0 Oti9 O.yO On�'1.O�ti 03M 0,5b o,5y O''t° O''� O.yO O''°' Op0 Ob'1.Obi'Ob'' O' ODh Opro Oa't
ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti ti
Oregon Residential Gas Heating Market Transformation Idaho Residential Gas Heating Market Transformation
Space Heating Equipment Stock Space Heating Equipment Stock
Moog 100% - 100%
90% ■Air-Source Heat Pump(ENERGY 90% ■Air-Source Heat Pump(ENERGY
STAR 6.1)-Boiler STAR 6.1)-Boiler
� 80% 80%
■Air-Source Heat Pump(ENERGY ■Air-Source Heat Pump(ENERGY
70% STAR 6.1)-Furnace 70% STAR 6.1)-Furnace
0 0
y 60% ■Dual-Fuel Heat Pump-AFUE 95% w 60% ■Dual-Fuel Heat Pump-AFUE 95%
i 50% = 50%
■Dual-Fuel Heat Pump-AFUE 80% — ■Dual-Fuel Heat Pump-AFUE 80%
r 40% 40%
0 0
30% ■Gas Boiler o 30% ■Gas Boiler
20% ■Gas Furnace 20% ■Gas Furnace
10% 10%
0%
,LOT,LOT,LOT LT OT5 01G' 01�' 01�' OTO O'hO 03'y 03ti 00'S 00P 00y 00G 03� O'i4 O'i9 OCO` OC'`Y Obti Ob'S OPP Obh OaG Oa't do oLL ,L 3 d,L b,o`1 G ti t o,L 0 d" d,, `1 o 41
9 tio°°
0%
Applied Energy Group,Inc. I appliedenergygroup.com 10
2025 Natural Gas IRP Appendix 568

w•
e
Thank You .
t.
+y zp t- 'Y
A G
.y
Phone: [phone] APPLIED ENERGY GROUP

2025 Gas Integrated Resource Plan
Technical Advisory Committee Meeting No. 7 Agenda
Wednesday, August 21, 2024
Virtual Meeting
Topic Time (PTZ) Staff
Feedback from prior TAC 10:30 All
Natural Gas Market Overview 10:40 Tom Pardee
Natural Gas Price Forecast 11 :20 Michael Brutocao
Avoided Cost Methodology 11 :30 Tom Pardee
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Join the meeting now
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2025 Natural Gas IRP Appendix 570

s uri'ISTA`
Natural Gas Market Overview
2025 Gas IRP — TAC 7

Wood Mackenzie does not warrant or represent that the Information is
appropriate or sufficient for your purposes and has not taken into account
the purposes for which you are preparing the Document or using the
Information and you acknowledge and agree that if you use or rely upon
the Information for any purpose then you shall do so entirely at your own
risk;
2025 Natural Gas IRP Appendix 572
2 mill-VISTA

Key assumptions
Key macro and oil assumptions
Macro assumptions Gas and LNG assumptions
Geopolitics US LNG pause
• Sanctions and bans on Russian exports remain in place through to 2030 but The Biden administration's pause on granting new non-FTA approvals for US LNG projects
ease thereafter with 'normality' re-established from 2035. lasts until the end of 2024 and is relaxed in 2025 after the elections.
• While we continue to see an increase in bilateral conflicts,as per the recent Existing and under-construction projects are not impacted.
events between Iran and Israel, we do not assume an escalation to a multilateral Some projects with existing non-FTA approval that are set to expire before the expected
conflict in the region. We assume the war and the Red Sea transit issues end commissioning could proceed to FID in 2024. Consensus is emerging that non-FTA extensions
before Q4 2024. will be granted if the project can provide a reasonable explanation for delayed FID since the first
Macroeconomic outlook approval.We assume one project sourcing gas from the US will take FID in 2024.
• Inflation continues to decline: interest rates loosen in 2024 Russian gas and LNG supply
• Global economy to hold steady in 2024 but weakness in Europe and China Pipe exports to the EU decline further after 2024 as the Russia-Ukraine transit contract expires.
provide recession risk. New pipelines to China, including the Far East(2028)and Power of Siberia 2(2033)pipelines.
• Geopolitical tensions increase as China and the G7 compete for ties with non- continue to develop.
OECD and BRICS+ Western sanctions create issues for Russian LNG—we have risked the production profile of the
• Global GDP growth of 2.2% (CAGR), 2028 to 2050 existing and under-construction projects and assume no new Russian LNG FIDs for the
Energy transition foreseeable future.
• Energy and environmental policy continue to focus on COz reduction, but Sanctions-related issues with ice-class LNG shipping restrict the use of the Northern Sea Route
countries fail to achieve net zero targets. to Asia. The European Parliament passed rules allowing EU governments to restrict Russian
• Global temperature rise to around 2.5 °C compared to LNG imports. but until a formal ban is in place, we assume imports continue.
pre-industrial levels. Energy policies and implications for gas
• Europe: gas demand continues to decline in line with Fit-for-55 targets. but the EU fails to
achieve RePowerEU targets. Some decarbonisation initiatives. like electrification of heating.
face challenges.
• US: IRA supports renewables development, but scaling up to ambitions remains tough. resulting
in resilient gas demand.
• Asia: after stagnating in the near term, gas demand returns to growth in key emerging markets,
reaching 15.4%of regional primary demand by 2050 versus about 11%in 2024.
Wood
ackenzie
2025 Natural Gas IRP Appendix 573
3 �111 VISTA

North America natural gas at a glance
Gas market expands by over 30% until early 2040s to reach over 160 bcfd
Associated supply growth accelerates but LNG exports triple by 2050 despite near term delays in Henry Hub gas prices reach
peaks by mid-2030s the US $6/mmbtu by late 2040s
160 50 ■
■ 58
ao
140 ■� 30
w
U
120 - 20
$6
100 10 «
0 E
SO 2020 2030 2040 2050 E
44
US/Canada LNG exports ■US piped Mexico exports CO) $4
A
so Stronger power load growth supports A
40
resilient domestic gas demand R
■ Rescom � $2
20
Industrial and
0 blue hydrogen
2020 2025 2030 2035 2040 2045 2050 $
Power 2020 2020 2025 2030 2035 2040 2045 2050
■Associated ■Non-Associated ■Renewable 2030
2040 —Henry Hub —Waha
Wood ■Others ` — Eastern South Point —AECO
ackenzie
2025 Natural Gas IRP Appendix 574
4 '164-°IwIsra

Supply
North America gas supply grows yearly by an average of 3.3 bcfd until the mid-2030s
before stabilizing near 160 bcfd through 2050
Permian associated gas is the largest growth region over the next five years, however, the Haynesville is the
largest growth area over the next ten years; Post-2040 there is a greater call on non-associated gas sources
North America gas by type
160 80% RNG production grows tenfold between 2023 and 2050 supported by low carbon
policies, such as the Low Carbon Fuel Standard (LCFS). Renewable Fuel Standard
140 rrrrrrr�r 70% Renewable (RFS)and the Inflation Reduction Act(IRA),and ample resources of landfill and
dairy biogas feedstock.Still, in the long term, RNG supply will be a modest 3%of
120 —` 60% the total North America natural gas supply.
0
Softer near-term gas prices negatively impact short term non-associated gas supply
100 50% a growth.However.growing demand in the medium term will need to be met by growth
Non- from non-associated regions.Gulf Coast,Western Canada and the Northeast will grow
Associated by a combined 24 bcfd by 2035 from current levels.Haynesville could deliver 11 bcfd of
80 — 40% growth by 2035.Continued Northeast supply growth is needed to meet demand in the
longterm.
60 __ _ 30% Strong oil pnces support liquids-focused drilling activity.bringing large volumes of low-
cost associated gas to market.This temporarily delays some non-associated gas
40 20% Associated growth until later in the forecast.Associated gas growth is fueled by the Permian and
Western Canada.The Permian accounts for 80%of associated gas growth by 2035.
adding 8 bcfd from 2024 levels,followed by 11%coming from WCSB adding 1 bcfd.
20 10%
[No Title]
0 -------- ------------------- 0%
2020 2025 2030 2035 2040 2045 2050
Associated Non-Associated Renewable
-—%Associated ———% Non-Associated % Renewable
rood
I� Mackenzie
2025 Natural Gas IRP Appendix 575
5 O°lw�sra

Supply
North America has significant gas resource available for development
In addition to commodity prices, factors such as demand, well economics, infrastructure, regulations, emissions
considerations and investor sentiment will dictate how much resource is ultimately produced
Remaining gas resource for key regions
1000
800
UU
It 600
d
U
O
U0
U) 400
C�
200
0
Northeast Gulf Coast Permian Canada Rockies and San Juan Midcontinent Others'
■Produced ■Remaining
AWood
Mackenzie
2025 Natural Gas IRP Appendix 576
6 ki VISTA

Supply
With appropriate technology development and policy frameworks, North America
renewable natural gas (RNG) production will grow to over 4 bcfd by 2050
RNG production capacity has doubled since 2020, and more projects are expected to come online in the long
term supported by ample landfill and dairy farm resources
RNG production forecast by region
British Columbia, Quebec and Ontario lead RNG production as local utilities and
government aggressively commit to net carbon-zero targets and stakeholders
Canada capitalize on credits from the Clean Fuel Standard. RNG producers invest in
4 development of new feedstock types and technologies that take advantage of local
resources.
RNG production in Texas benefits from proximity to LNG export facilities. Major
o US Gulf players in the industry look at RNG to decarbonize shipments to oversees markets
with aggressive emission reduction targets. Landfill gas sites dominate the supply
�i Coast mix in the region, but producers also invest in large farm projects in the area to
u �do utilize environmental credits available in the transport sector.
a �
i
i
More RNG facilities come online as utilities and states seek to fulfill GHG emission
US reduction goals.which are one of the most aggressive in the nation.Ohio.
i� Northeast Pennsylvania and Indiana are among top five states with highest RNG production in
our forecast. benefiting from large landfill projects and dairy RNG potential.
1 �
Pioneering the nation with its progressive low-carbon policies, the west leads in
US Pacific new dairy project developments until the late 2020s. California remains the top
RNG producer in our forecast,but we expect demand will transition from fueling
0 r NGVs to fulfilling LDC and industrial sector.
2020 2025 2030 2035 2040 2045 2050
West North South iiiiiiiiiiiiiiiiiiiiiiiiiiiiiCanada ———Oct 23
AWood
I� Mackenzie
2025 Natural Gas IRP Appendix 577

Demand
Gas plays a pivotal role in the energy transition with its market share in the energy mix
growing by 5% from 2025 to 2050 at the expense of coal and oil
Gas represents about 40% of North American total energy demand in 2050
Primary energy demand mix* in North America
Mtoe Gas demand continues to climb throughout the
Canada decades with the emergence of blue hydrogen
� 40 developments and new industrial opportunities
■ Nuclear • The near elimination of coal and decrease in oil
■ Bio energy 350 ,+ ' Canada demand is driven by switching to gas for power and
300 continued expansion of renewables.
■ Renewables 250 • New technologies including large scale CCS
Hydro till projects create an environment for reduced
200 emissions, allowing expansion in demand.
■ Oil 2,500 United States
150 • • Gas demand grows at a CAGR of 0.7%between
Coal 100 2025 and 2035.driven primarily by growth in blue
2,000 ! hydrogen and industrial sectors.
■ Gas _ 50 I • Between 2035 and 2050, the CAGR drops to-0.4%
1,500 0
due to the energy transition, such as gas
2025 2035 20 01�� United displacement from low-carbon hydrogen in the
States industrial sector and building electrification in the
1,000 LDC sector.
• Gas remains resilient in the power sector and
supports more robust load growth through the
500 2030s, but rising renewable generation erodes gas
demand in the 2040s albeit at a more gradual rate
0 compared to the previous outlook.
2025 2035 2050
Wood
ackenzie
2025 Natural Gas IRP Appendix AN 578
g �Ilw�sra

Demand
North America domestic gas demand will continue to rise well into the 2040s
Gas use in the power sector continues to be resilient, driven by the retirement of coal-fired plants in the near
term and sustained power demand growth stemming from data centers and industry reshoring in the long term
North America gas demand by sector Transportation demand includes the consumption of natural gas in vehicles and small-
scale bunkers.We expect the demand to grow from 0.4 bcfd in 2024 to 2.5 bcfd in
Transport 2050-This growth will be bolstered by widespread adoption of RNG.substantial
1 20 funding and tax credit from the IRA for the US market.as well as recent technological
advancements in gas engines for heavy-duty trucks.
———�-- North America will lead blue hydrogen supply with over 56%of global production by
2050. requiring 10.4 bcfd of gas demand. The momentum is highly concentrated in
Blue the US as the Production Tax Credit announced under the IRA remains one of the
hydrogen market's most robust financial support mechanisms for low-carbon hydrogen. Three of
-' the seven hubs selected by the DoE in 2023 to receive USS7 billion in funding will be
blue hydrogen hubs and help drive growth.
6D Other With rising gas production and LNG exports,we expect other demand to grow by 4.3
bcfd between 2024 and 2050.
We expect the combined demand for residential and commercial sectors to peak at
-1 D LDC 26.2 bcfd in the early 2030s.The subsequent decline can be attributed to the
(residential displacement of demand by hydrogen and the ongoing building electrification. In this
and update, we see potential upside risks from slower adoption of building electrification,
20 commercial) influenced by preemptive US legislation and reduced heat pump sales.
Industrial demand will reach 30.3 bcfd in 2024 and peak at 33.54 bcfd by 2035.We
expect over 50 new industrial projects in the US and Canada to be commissioned
0 Industrial between 2024 and 2031 to facilitate this expansion.Over the long term, North
2020 2025 2030 2035 2040 2045 2050 American industrial demand will decline to 31.9 bcfd by 2050- This is due to replacing
Power Industrial —LDC — Other grey hydrogen with low-carbon hydrogen in the ammonia,refining, and methanol
Blue Hydrogen Transport ——— Oct 23 sectors.
Although gas demand in the power sector will decrease by 8%over the next decade.
Source: Wood Mackenzie the decline is much more gradual compared to our previous update,as gas'share in
Wood Mackenzie's "Other Demand" matches the EIA definition, which is lease and plant fuel an, Power the power market will stay close to 30% by 2040. Stronger power load growth from
pipeline losses. It is the gas used within the industry, where the two biggest components to data centers used for At,cloud computing,digitization and industry reshoring—
particularly the semiconductor industry—requires gas to help support the grid as solar
W1v (the more supply the more L&P fuel)and LNG exports. and wind continue to face transmission constraints.
Wood ackenzie
2025 Natural Gas IRP Appendix AIIIN 579
9 �llwIsra

Dernand
Compared to prior outlook, North America sees about 5% higher overall power loads
from data center buildout and re-shoring of semiconductor industry
Decline of gas share in power stack is much slower as renewables see limited growth from challenges with
interconnection queues and transmission bottlenecks
North America power generation by type Levelized cost of energy (LCOE)
8,000 50% 350
300
6,000 %% 40%
250
3: 200
4,000 - 30% e a
t m �-
t p 150
N J
2,000 20% 3
100
50
0 10%
024 2028 2032 2036 2040 2044 2048
0
2020 2025 2030 2035 2040 2045 2050
-2,000 0%
—Gas-CC —Gas-CC+CCS
Coal Gas Nuclear —Coal —Coal-Conventional +CCS
Hydro Solar Wind —Geothermal —Nuclear
Other Battery Storage ——— Gas share —Gas-CT —Wind-Offshore
—Wind-Onshore —Hybrid-PV-Utility
Wood
ackenzie
2025 Natural Gas IRP Appendix 580

Market balances and trade flows
US exports to Mexico almost double by 2050 as west coast Mexican LNG exports gain
momentum while indigenous production declines
The Biden administration's DOE non-FTA permit approval pause delays some US LNG projects in the near term
but the prospect for more pre-FID North America LNG remains bright
North American piped trade flows North American LNG exports
14 • Mexico's gas dernand continues to exhibit resilience.buoyed by the sustained
momentum of GDP growth.Over the period from 2024 to 2050,the projected &L C* 45
CAGR stands at 1%,resulting in an increase of nearly 2 bcfd from 2024. '
12 primarily driven by the industrial sector.Concurrently,the trajectory of gas-to- 40
power consumption is poised for a gradual uptick as the adoption of
renewable energy sources gradually displaces traditional gas usage. 35
10
4+0*AF-
30
8
25
� w
6 LNG exports are positioned as the key driving force for demand in the 20
country.commencing with Altamira in 2024.Costa Azul in 2025.and
Saguaro in 2029.This phased progression is set to substantially
4 escalate US piped gas requirements,surging nearly 4 bcfd by 2034 �'�� 15
and close to 6 bcfd by 2050.
10
2
5
0 0
2020 2025 2030 2035 2040 2045 2050 2020 2025 2030 2035 2040 2045 2050
—US to Mexico —US to Canada —Canada to US Existing ■Under construction ■Pre-FID
rAWood
Mackenzie
2025 Natural Gas IRP Appendix 581
11 A°lw�sra

North America liquefied natural gas export facilities, existing and under construction
(2016-2027) e0 "
•LNG Canada
Woodfibre LNG
Canada
LNG terminals
Existing
• United States United States
Cove Point•
Under construction
0 Canada
• Mexico •Energia Costa Azul LNG
• Elba Island
• United States
Production capacity (Bcf/d) Freeport® 0 Plaquemines Cameron
Comas Christi • Port Arthur
Corpus Christi Stage III
lower than 0.6 Rio Grande LNG Golden Pass Calcasieu
0.6-1 .5 Mexico Pass Pass
Fast LNG Altamira
1 .6-2.5 •
2.6 or higher •Fast LNG Lakach Freeport
Data source: U.S. Energy Information Administration, Liquefaction Capacity File, and trade press
Note: Bcf/d=billion cubic feet per day. Map current as of October 2023.
2025 Natural Gas IRP Appendix 582
12 dki VISTA

Price&margin outlook
Henry Hub prices reach $6/mmbtu by late 2040s
Henry Hub prices rebound to $3.50/mmbtu by 2026 with rising LNG exports and restraints from non-associated
producers on supply growth
Gas price outlook
(2024-2025)
Bloated storage inventory pressures prices to the
downside, but LNG project ramp-ups begin to tilt the
market to balance,especially with near-term production
curtailments.
(2026-2031)
North America LNG exports increase substantially with
Z _ delayed US projects but also from accelerated Canadian
E �.-- and Mexican projects. Despite higher associated supply
E led by higher oil prices. restraints from non-associated
"' producers could prevent the market from becoming
2 oversupplied again.
v
(2032-2038)
Market expansion continues with more US LNG exports
$2 and domestic demand growth—notably from a more
resilient power sector. Henry Hub prices stabilizes through
sustained growth in the associated supply until mid-2030s
and a Haynesville production rebound.
g_ (2039-2050)
2020 2025 2030 2035 2040 2045 2050 The size of the gas market peaks by the early 2040s and
declines in associated and Haynesville production put
Apr 2024 ——— Oct 2023 significant upward pressure on Henry Hub prices
especially with demand resiliency in the power sector.
Wood Production from legacy gas basins increases to moderate
ackenzie Henry Hub prices from spiking up.
2025 Natural Gas IRP Appendix 583
13 "AIVISra

Price&margin outlook
AECO weakens in the long term as WCSB still requires piped exports to clear marginal
supply despite new LNG exports
Supply competition intensifies for Eastern Canada in the long term with stable market demand and the Northeast
wins out with widening Eastern South Point-Dawn spread
Western Canada Eastern Canada
• LTFP on TC Mainline is set to expire in 2027 with no
resolution in place for producers. Transportation rates
are expected to increase.widening the Dawn-AECO
1 spread to support flows on the TC Mainline.
$0) Dawn provides a crucial outlet for Northeast supply in
the long term due to stable market demand and will be
m increasingly influenced by Eastern South Point.
CO
E E 0
• LNG Canada Phase I could tighten up AECO basis in
Vtemporary but abundant low-cost WCSB supply keeps v _1
a downward pressure on basis especially as LTFP to Dawn N
ends on the TC Mainline-
$(3) However. an accelerated Canadian profile exhausts low-
cost supply faster in the 2030s with Montney production -2
peaking by early 2040s.AECO basis stabilizes in the long
term to result in higher in-basin prices to incentivize
production from Deep Basin and even Liard in the long term.
$(4) -3
2020 2025 2030 2035 2040 2045 2050 2020 2025 2030 2035 2040 2045 2050
—AECO —West Coast Station 2 —Dawn —Eastern South Point —Chicago AECO
Wood
ackenzie
2025 Natural Gas IRP Appendix 584
14 �uI VISTA

outlookPrice and margin
NorthPrice risks
gas prices
• Early termination of US •
Strength of the impact on price
Low AHigh
Restrained spending by
N non-associated producers Continued re-shoring of CCS and blue hydrogen
� DOE's non-FTA export power-intensive industries emerge as mainstr
� permitting pause to result
� in more US LNG FIDs Pipeline development and data center growth technologies
a delays in the Haynesvill
� Intensified LNG supply Energy transition picks up
:° competition with Non- Upstream exploration
� Economic concerns in pace to replace gas
3 Europe or Asia impacting North America LNG demand with success and efficiency
-°a LNG demand projects reaching FIDs or electrification or green gains in second tier or
u, return of Russian exports legacy gas basins
c, hydrogen adoption
� to Europe
L
a
...

Natural Gas Market Price Forecast
Michael Brutocao, Natural Gas Supply Analyst
Technical Advisory Committee Meeting No. 7
August 21 , 2024

Henry Hub Expected Case Price Forecast
$12 100"- . Levelized Price: $4.95
• Data Sources
$10 — NYMEX forward market prices on
75% August 5, 2024
AA ` Annual Energy Outlook 2023
c
$8 ^ '1 ' — Consultants 1 & 2 monthly price
E forecast
0
Z $6 50% • Methodology
o A — Average price of forecasts
�, $4 — Decreasing blend of NYMEX
25% NYMEX Other
$2 2026 100% 0%
2027 75% 25%
$- 0% 2028 50% 50%
to f-- 00 d') O N co It LO O ti 00 O O N co LO
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2029 25% 75%
N N N N N N N N N N N N N N N N N N N N
C: c C C C C C C: C: C: C: C: C: C: C: C: C: C: C: 2030 - 2045 0% 100%
—Expected Case EIA/AEO Consultant 1 Consultant 2 Nymex
-
Annual Energy Outlook 2023 — Natural Gas Spot Price at Henry Hub 2025 Natural Gas IRP Appendix
2

Henry Hub Stochastic Price Forecast
$16 $16
• Stochastic Inputs $14 $14
— Expected Case Forecast $12 $12
• Data Source:See previous slide
— Autocorrelation (94.31%) $10 $10
• Data Source: Historical monthly prices at Henry Hub Z
— Standard Deviation of Errors $8 $8
• Data Source: Historical daily NYMEX forward market prices $6 - $6
• Data Source: Historical monthly prices at Henry Hub
$4 ---- - $4
140% $2 $2
120%
80% N N N N OM CO CO CO CO CO CO CO COO CO It It It It It It
O O O O O O O O O O O O O O O O O O O O
60% N N N N N N N N N N N N N N N N N N N N
40% Percentile: 25% Input Mean Percentile: 95%
20% -(00000�
0%
c01­ 00MO NM � LOCOI,- OOMO NM lf)
It It It It . Methodology
N N N N M M M M M M M M M M
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N Start from Expected Case Forecast
— Perform adjustment for Autocorrelation to prior month
Standard Deviation of Errors — Randomly draw from prices with lognormally distributed standard deviation of errors
-
Historical Monthly prices at Henry Hub 2025 Natural Gas IRP Appendix
3

Henry Hub Stochastic Price Forecast = Levelized
20%
18%
16%
14%
12%
10%
8%
6%
4%
2%
0%
O Ln O Ln O Ln O Ln O Ln O Ln O Ln O Ln O Ln O
Ln n O cV Ln r- O (V Ln n O cV Ln n O N Ln r- O
. . . . . . . . . . . . . . . . . . .
M M 4 4 4 4 Ul Ul Ul Un lD lD ,6 lD n � � n 00
u1 O u1 O Ln O u1 O u1 O u1 O u1 O Ln O u1 O U1
cV Ln � O cV U) � O fV U) I- O fV In r- O cV In r-
. . . . . . . . . . . . . . . . . . .
M M M 4 4 u1 u1 U1 u1 lD l.6 .6 l6 I�
$ / Dth - Nominal
2025 Natural Gas IRP Appendix
Data Source: Consultant 2 percent basis price differential to Henry Hub forecast
4

All Basins Expected Case Price Forecast
$10 $10
$9 $9
$8 $8
$7 $7 Levelized Prices
$6 $6 Henry Hub $4.95
Z $5 $5 AECO $3.67
0
$4 ,J �JV $4
" Sumas $4.30
$3 W $3
Malin $4.38
$2 $2
Stanfield $4.21
$1 $1
C0 Il- 00 m O N CO LO CD I� 00 0) O N CO LO
N N N N ce) m CO CO m CO CO CO CO m It It It It It 't
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
(6 (6 (0 (Q (B (B (B (0 (B (6 (6 (6 (6 (0 (Q (B (B (B (B (6
Henry Hub AECO Sumas Malin Stanfield
2025 Natural Gas IRP Appendix
Data Source: Consultant 2 percent basis price differential to Henry Hub forecast
5

YAW
Avoided Cost Methodology
2025 Gas I RP — TAC 7 r�

EE Rules guidance = Idaho
• Include commodity, Interstate transport costs and current policy and
distribution component, if measurable to avoid , in the avoided cost
calculation
The distribution component calculation once determined must be presented to the
Commission for approval and included in the IRP DSM avoided cost calculation.
(CASE NO. INT.G.22-03)
2025 Natural Gas IRP Appendix 592
2

EE Rules guidance = Oregon
OAR 860-030-0007
Gas Utility Avoided Costs
• (1) Investor-owned gas utilities shall file a proposed avoided-cost method and draft avoided costs with their
integrated resource plans pursuant to Order No. 89-507. The avoided-cost method filed should be appropriate
for determining the cost effectiveness of weatherization measures from the gas utility's perspective.
• (2) A gas utility may propose, or the Commission may require a gas utility to file the data described in OAR 860-
030-0007 (Gas Utility Avoided Costs)(1 ) during the two-year period between filing integrated plans pursuant to
Order No. 89-507 to reflect significant changes in circumstances, such as acquisition of a major block of
resources. Such a revision will become effective 90 days after filing.
• (3) At least every two years, the gas utility must file with the Commission the data described in section (1 ) of this
rule.
• Current Elements in UM 1893 from the companies most recently acknowledged IRP
Global Inputs (Discount rate, inflation rate, NWPCC 10% adder, system peak coincident day/hour factor)
Commodity & Transport (Gas commodity and transportation/storage costs)
Environmental Compliance (environmental compliance cost)
• Infrastructure Capacity (forecast of distribution system capital costs)
• Risk Reduction (a value for commodity risk)
• End Use Profiles (end use profile by source and customer class)
2025 Natural Gas IRP Appendix 593
�IIII VIISTA
3

EE Rules guidance = Washington
Gas companies—Conservation targets.
(1) Each gas company must identify and acquire all conservation measures that are available and cost-effective. Each company must establish an
acquisition target every two years and must demonstrate that the target will result in the acquisition of all resources identified as available and cost-effective.
The cost-effectiveness analysis required by this section must include the costs of greenhouse gas emissions established in RCW 80.28.395. The targets must be
based on a conservation potential assessment prepared by an independent third party and approved by the commission. Conservation targets must be
approved by order by the commission. The initial conservation target must take effect by 2022.
(2) The commission may require a large combination utility as defined in RCW 80.86.010 to incorporate the requirements of this section into an
integrated system plan established under RCW 80.86.020.
[ 2024c351 s 17; 2019 c 285 s 11.]
NOTES:
Findings—Intent—Effective date-2024 c 351: See notes following RCW 80.86.010.
Findings-2019 c 285: "(1) The legislature finds and declares that:
(a) Renewable natural gas provides benefits to natural gas utility customers and to the public; and
(b) The development of renewable natural gas resources should be encouraged to support a smooth transition to a low carbon energy economy in
Washington.
(2) It is the policy of the state to provide clear and reliable guidelines for gas companies that opt to supply renewable natural gas resources to serve
their customers and that ensure robust ratepayer protections." [ 2019 c 285 s 12.]
2025 Natural Gas IRP Appendix 594
�IIII V�STa
4 RCW 80.28.380: Gas companies—Conservation targets. (wa.gov)

Standard Cost Effectiveness Tests
F7-
Total utility
Resource Considers the impact Measures the cost to allTestact to p
Cost A involved the utility
Societal in nature L Determines if programs
Adjusting incentive does are deferring capitalinvestments
not impact TRC
We can adjust incentive
to impact UCT*
2025 Natural Gas IRP Appendix I II 595
�I V�sTa
5 *Adjusting incentives too much in pursuit of UCT may reduce participant enthusiasm

Cost Effectiveness Items
EEBe n ef i Ism Costs 1-geneftt Compo
Avoided Cost of Utility Energy S S
MO
Value of Non-Utiity Energy SavingsNon-Energy --I 3
Non-[nergy I mpacts $
Impacts Reduced Retail Cost of Energy
Customer
CostsIncremental Customer Incremental Cost S
Avoided Energy Utility Incentive Cost S
cost Incentive
costs
Utility Non-Incentive Cost $ S
Non-Incentive Imported Funds(tax credits, federal funding etc)
Impacts (S)
CostsReduced Retail Revenues
2025 Natural Gas IRP Appendix 596
�IIII I/ESTA
6

Idaho = Avoided Costs Input
( Res, Com , Ind)
Commodity Interstate Pipeline Local Distribution
Contracts
capitalNatural Gas Variable Costs
L If •
forecastL are
• • • -
L Fuel •
Methanation
Valued at • - .
Reservation • hour
*Interstate Pipelines include GTN, NWP, NIT, Foothills, West Coast 2025 Natural Gas IRP Appendix 597
7 **Storage costs from JP are excluded. Facility will need to be maintained (reliability, safety, operability) regardless of use. 4iI'VESTA
***Local Distribution is excluded from interruptible customers of any class

Oregon and Washington = Avoided Costs Input
( Res, Com , Ind)
Interstate Local
Commodity Pipeline Distribution*** Carbon Adder
Contracts*
NWPCC 10%
capitalNatural Gas F- Include
Variable Costs If •
costs •
forecast
I L Hydrogen Fuel Costs NEI
. . O -
Meth. •
Reservation
costs peak hour •
*Interstate Pipelines include GTN, NWP, NIT, Foothills, West Coast 2025 Natural Gas IRP Appendix 598
**Storage costs from JP are excluded. Facility will need to be maintained (reliability, safety, operability) regardless of use. A�MISTA
8 ***Local Distribution is excluded from interruptible customers of any class

Oregon and Washington = Avoided Costs Input
(Transport**)
Interstate Local
Commodity Pipeline Distribution**** Carbon Adder
Contracts*
NWPCC 10%
capitalNatural Gas F- Include
Variable Costs If •
costs •
forecast
L Hydrogen Fuel Costs NEI
. . O -
Meth. •
Reservation
costs peak hour •
*Interstate Pipelines include GTN, NWP,NIT, Foothills,West Coast(Avista contract costs as estimate)
**Only transport suppliers included in Avista's CCA and CPP obligations 2025 Natural Gas IRP Appendix 599
/III_
***Storage costs from JP are excluded. Facility will need to be maintained(reliability,safety,operability)regardless of use �sTa
9 ****Local Distribution is excluded from interruptible customers of any class

Avoided Cost (example only)
$6.00
Total Avoided Cost: $5.39
$5.00 Carbon Adder,
$1.00
NEI, $0.10
$4.00 Distribution, $0.30
NWPCC 10%, $0.49 ■
s
p Interstate PL, $0.50
$3.00
$2.00
Commodity, $3.00
$1.00
$- ,,�,1 II++
2025 Nat P*VG2i19PAppedO&St 600
�i IVISTA
10

DRAFT
2025 Gas Integrated Resource Plan
Technical Advisory Committee Meeting No. 8 Agenda
Wednesday, September 25, 2024
Virtual Meeting
Topic Time (PTZ) Staff
Feedback from prior TAC 10:30 All
Heat Pump Efficiency 10:40 Tom Pardee
Electrification Costs 11 :20 Tom Pardee
Microsoft Teams Need help?
Join the meeting now
Meeting ID: 232 105 574 200
Passcode: JmeAyM
Dial in by phone
[phone]„62195212# United States, Spokane
Find a local number
Phone conference ID: 621 952 12#
For organizers: Meeting options Reset dial-in PIN
2025 Natural Gas IRP Appendix 601

s uri'ISTA`
Heat Pump Efficiency
September 25, 2024

DRAFT
Climate Zones
• Avista LDC territory comprises 3
climate zones
Climate Zone 4: Roseburg, Medford
Dry(B) Moist(A)
Climate Zone 5: La Grande, Spokane Marine(C)
Climate Zone 6: Northern WA and ID - �-
Climate Zone
• Climate zones help determine l := z
..
sizing of heat pumps and furnaces == ' = 3
I" Warm-Humid = 4
Below White Line
■ = 5
Zone btu needed per s . ft ■ - 6
All of Alaska is in Zone 7 exceu. 2 ■ = 7
1 35 the following boroughs which are in
Zone 8:Bethel,Dellingham,Fairbanks
2 40 N.Star,Nome,North Slope,Northwest Zone I includes Hawaii.
3 45 Arctic,Southest Fairbanks.Wade
Hampton.Yukon-Koyukuk Guam,Puerto Rico,and
n
4 50 the Virgin Islads
5 55
2025 Natural Gas IRP Appendix 603
DRAFT d,-4I VISTA

DRAFT
Basic Calculation Considerations of Heat Pumps
• Output Btu
• Input Btu 60,000 350%
50,000 - '--_ 300%
• Temperature in Fahrenheit 40,000 250'
�
0 200%
_ a
w 30,000 0
• Coefficient of Production 150%
20,000
100%
10,000 —Input in Btu 50%
• Climate zone -Output Btu
--COP
- 0%
65 61 57 53 49 45 41 37 33 29 25 21 17 13 9 5 1 -3 -7-11-15-19
• House size Degrees Fahrenheit
ASHP (neep.or )
• Ducted Heat Pump
1 . Heat pumps need a higher ai20 pe a� e 'P�(?aide the same amount of heat from a furnace 604
DRAFT 2. Higher air flow requires bigger ducts �MISTA

DRAFT
COP including auxiliary
350%
—HP COP —Combined COP
300
250%
200
o_
O
U
150%
100
50%
0%
ri I- O M L.0 M N L n W 1-1 zt r, O M l0 M N L n W 1-1 zt I, O M lD M
r-I .-I .-I r-I N N N M M M I;t I;t IT L n L n L n l0 l0 lD I- r- r- r-
HDD
DRAFT Assumes 100% efficienivleet6vfwnace as auxiliary backup heat d'l 605

DRAFT
Detailed Calculation and Considerations
• Cubic foot of heating volume (L x W x H) of structure
• Exposure to elements (shade, direct exposure)
• Window glaze (double pane, single pane)
• Room type (kitchen, hall, bedroom)
• Desired temperature increase
(desired temperature change) x (cubic feet of space) x.080713 (Ibs of air per cubic foot)
• Auxiliary space heating (back up type) — Electric @ 100% efficiency
• Rates of electricity (kWh) vs. gas (therm)
• Efficiency of heat pump
2025 Natural Gas IRP Appendix 606
DRAFT 0
Takeaway: a lot of variability for heat needs depending on home size, location, efficiency, shell and climate �ilii/ISTA

DRAFT
Rates of Energy
• The energy rate (kWh or therm) has a great deal of impact on
overall costs with switchover temperature
• Although heat pumps provide a great deal of savings of btus,
when colder weather occurs the efficiency declines (COP)
2025 Natural Gas IRP Appendix 607
DRAFT eduVISTA

DRAFT
12°,°°°
Oregon Example
Current Heat Pump Efficiency =Auxiliary Needs for HP
—Desired Temp Change(Btus per hour) —Basic Calculation of Heat needs by zone
100,000
• Avista 2024 Rate per therm: $1 .26 80,000
3
O
2
n 60,000
• 2024 Res Rate per kWh:$0. 13 (blended PAC and
City of Ashland) 40,000
20,000
• 2000 sq. ft. house
0
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79
HDD
• Climate zone 4 $5.00
—Avista Electric HP Costs per hour Residential
$4.50
—Avista Gas Costs per hour
• Gas furnace efficiency: 80% $4.00 Residential
$3.50
Y
f0
_ $3.00
° Economic
o $2.5o Switchover
V
$2.00 at 31 HDD
_ $1.50 to a gas
furnace
$1.00
$0.50
$0.00
0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66 69 72 75 78
HDD
2025 Natural Gas IRP Appendix 608
DRAFT
*does not assume a lock out temp on heat pump /ISTA

DRAFT
Washington Example
120,000
100,000 =Current Heat Pump Efficiency
=Auxiliary Needs for HP
• Avista 2024 Rate per therm : 80,000 —Desired Temp Change(Btus per hour)
—Basic Calculation of Heat needs by zone
$ 1 .556
0
0 60,000
m
40,000
• Avista 2024 Res Rate per 20,000
kWh : $0. 11582 0
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79
HDD
• 2000 sq . ft. house $4.00
—Avista Electric HP Costs per hour Residential
$3.50
—Avista Gas Costs per hour
Residential
$3.00
Economic
• Climate zone 5 = $2.50 Switchover at 52
o $2.0o HDD to NG
furnace
2.
• Gas furnace efficiency: 80% _ $1.50
$1.00
$0.50
$0.00
0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66 69 72 75 78
2025 Natural Gas IRP Appendix HIDD 609
DRAFT *does not assume a lock out temp on heat pump ,edii Ill ISTA

DRAFT
Current Rates with a 95% efficient NG furnace
Oregon Washington
$5.00 —Avista Electric HP Costs per hour Residential $4.50 —Avista Electric HP Costs per hour Residential
$4.50 $4.00
—Avista Gas Costs per hour —Avista Gas Costs per hour
$4.00 Residential $3.50 Residential
$3.50
$300 Economic
o $3 00 0 $2.50 Switchover
o $2.50 Economic o at 42 HDD
$2.00
$2.00 Switchover at to NG
_ $1.50 14 HDD to NG = $150 furnace
$1.00 furnace $1.00
$0.50 $0.50
$0.00 $0.00
0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66 69 72 75 78 0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66 69 72 75 78
HDD HDD
2025 Natural Gas IRP Appendix 610
DRAFT *Same assumptions as previous slide, just efficiency of NG furnace changed ed°I 7110MTA

DRAFT
Summary
• Heat pumps may be a good alternative depending on climate zone, house size and insulation as a primary source of
heating
This is magnified in areas of low electricity rates
• Heat pump life cycle is generally less than half of expected life cycle of a gas/electric furnace (Additional capital)
• Heat pumps provide additional benefits like cooling that may be considered when switching to or replacing a furnace
• Costs of energy and rates may alter the use of heat pumps for space heating, regardless of efficiency
• Defrost cycles in extreme weather may affect the usability during these cold events
• Costs:
depending on the customer type, heavy incentives may be available to help convert to heat pumps
If one commodity goes up or down more significantly than the other, the economic switchover temperature will change
There are thousands of different heat pumps, costs and related efficiencies so an industry estimate will be used as the assumed
price of installation
2025 Natural Gas IRP Appendix 611
DRAFT d,-4I VISTA

s uri'ISTA
Electrification Costs
Oregon and Washington

Electrification Estimated cost for
DRAFT
High Level Diagram of Process
evaluated/selected AEG Load Cost of Equipment space heat and
prior to gas load Forecast Rebates/Incentives water heat by area
forecast and class
DRAFT 'edi'l-wisy'a
Use per Customer Equipment cost
by day by area by estimate
class
Electricity rate by End use efficiency
service area by temp by area

DRAFT
Electrification Costs in the CROME Model
• Provides a price elastic response to higher gas costs and
compliance to the CCA and CPP
Customers were electrified in the end use model prior to the final gas load
forecast
• Once a unit is chosen at any point in time within the analysis, it is
removed for the remainder of the forecast timeframe
• If electrification is chosen, a program decision and methodology will
need to occur as well as a verified cost estimate to electrify:
Does Avista pay all costs or partially with electric provider?
How do costs get recovered?
Do all classes pay for these costs?
Trying to model costs and benefits, but not who pays (TRC test in EE)
2025 Natural Gas IRP Appendix 614
3 DRAFT edi VESTA

DRAFT
Clean Energy Targets
2025 Natural Gas IRP Appendix 615
4 DRAFT ediIVISTA

DRAFT
Oregon Clean Energy Targets
• Oregon
• In 2021 Oregon State Legislature passed the Clean Energy Targets
bill . This bill requires Portland General Electric, PacifiCorp and
Electricity Service Suppliers to reduce greenhouse gas emissions
from the electricity they provide. The bill also created targets for
these companies to reduce the greenhouse gas emissions from
electricity sold in Oregon to:
• 80 percent below baseline emissions levels by 2030;
• 90 percent below baseline emissions levels by 2035; and
• 100 percent below baseline emissions levels by 2040
Department of Environmental Quality : Oreago QIgpo Energy Targets : Action on Climate 616
Change : State of Oregon DRAFT d,-4i7-VJV5ra

*I::][::]
DRAFT GHG 000/NEUTRAL0 CLEAN /
Washington Clean Energy Targets 2025 2030 2045
NO COAL GHG NEUTRAL 100%CLEAN
STANDARD STANDARD STANDARD
• CETA applies to all electric utilities serving retail customers in
Washington and sets specific milestones to reach a 100% clean
electricity supply.
• The law requires utilities to phase out coal-fired electricity from
their state portfolios by 2025.
• By 2030, their portfolios must be greenhouse gas emissions
neutral, which means they may use limited amounts of electricity
generated from natural gas if it is offset by other actions.
• B 2045, utilities must supply Washington customers with
e ectricity that is 100% renewable or non-emitting with no provision
for offsets.
CETA Overview - Washington State Department of Commerce
2025 Natural Gas IRP Appendix 617
6 DRAFT eduVISTA

DRAFT
Electr'Ic a es
2025 Natural Gas IRP Appendix 618
7 DRAFT ediIVISTA

DRAFT
Electric Rate assumptions
• Current Rates for each provider and inflated to 2026 $ then
increased by estimated rate impact for Avista's electric $ per
kWh from Washington territory
• The resource mix of Avista as compared to Pacific Power is much
cleaner so the impacts to Pacific Power would likely be greater than
the estimate
- Pacific Power may use the clean resources from its portfolio to comply
with Oregon Clean Energy Targets
• Power provided by BPA is assumed as clean energy and
currently in compliance with clean goals
BPA does not have any excess power to sell in the event electric loads
increase for these electric providers, but for this analysis it is assumed
rates will increase by 3% YOY
2025 Natural Gas IRP Appendix 619
8 DRAFT eduVISTA

DRAFT
Washington Electric Provider Rates
Est.Total E.Wash electric
• Washington rates are weighted by # of customers
with crossover from natural
customers for each provider. MIL VERA Modern Inland Avista gas territory
• These providers are Avista (81 %), A 13,000 16,000 32,000 254,065 315,065
/o of Total Customers 4% 5% 10% 81%
Inland Power (10%), Modern Electric
(5%) and VERA water and power (4%) Current Rates as of June 2024
ELECTRICITY GENERATION Res $ 0.07 $ 0.06 $ 0.07 $ 0.09
RESOURCE MIX
As of Dec.31,2022-Excludes AEL&P Com $ 0.07 $ 0.06 $ 0.07 $ 0.14
Large Com $ 0.06 $ 0.06 $ 0.06 $ 0.09
0 Weighted Average Total Estimated Rate
59% Res $ 0.003 $ 0.003 $ 0.007 $ 0.073 $ 0.086
RENEWABLE
ENERGY Om $ 0.003 $ 0.003 $ 0.007 $ 0.111 $ 0.125
9 Large Com $ 0.003 $ 0.003 $ 0.006 $ 0.073 $ 0.085
Hydro 48%
wind 9%
Biomass 2%
Natural Gas 33%
Coal a%
2025 Natural Gas IRP Appendix 620
9 About Our Energy Mix (myavista.com) DRAFT edi VESTA

DRAFT
Oregon Electric Provider Rates
• Southern Oregon rates are weighted by # of customers Total Avista Gas
from each electric provider. Customers
City of Ashland Pacific Power S. Oregon
• These providers are the City of Ashland (12%) and Customers 11,000 83,601 94,601
Pacific Power (88%) /o of Total Customers 12% 88%
• La Grande has a single electric provider. Oregon Trail Current Rates as of June
Electric rates are increased by 3% YOY rather than the 2024 ($/kWh)
yearly increase to meet emissions goals Res $ 0.08 $ 0.14
Current Res kWh rate is $0.068 and Com $0.07 °m $ 0.09 $ 0.13
• Large Com $ 0.09 $ 0.09
Basic Service Total Estimated
Weighted Average Rate
Service you receive from the company's diverse resource mix. Res $ 0.01 $ 0.12 $ 0.13
Com $ 0.01 $ 0.12 $ 0.13
Unspecified
market purchase Large Com $ 0.01 $ 0.08 $ 0.09
a
■Coal-56.25% ■151%
■Nuclear-0.00% ■0.22%
■Hydro-5.13% O 4.20%
■Wind-9.00% ❑0.00%
■Biomass-0.34% M 0.22%
■Geothermal-0.34% O 0.00%
■Natural Gas-15.40% M 2.27%
0 Solar-3.62% ❑0.00%
■Biogas-0.00% ■0.00%
■Other-0.17% ■0.12%
Pacific Power may save the renewable energy credits associated with the eligible renewable energy(wind,solar,
biomass and some hydnJ in our Basic SerNce resource mix to comply with Oregon's Renewable Portfolio
Standard beginning in 2 1 1.For more information,visit DadfirnowernetlORros.
2025 Natural Gas IRP Appendix 621
10 OR Labeling Insert Large Business.pdf(pacificpower.net) DRAFT �iiVISTA

DRAFT
Electric Rate forecast
Commercial Rate Estimate Residential Rate Estimate
$0.40 $0.400
—WA Corn Rate —S.OR Corn Rate —La Grande Corn Rate —WA Res Rate —S.OR Res Rate —La Grande Res Rate
$0.35 $0.350
$0.30 $0.300
$0.25 $0.250
$0.20 m 50.200
Q a
$0.15 $0.150
$0.10 $0.100
$0.05 $0.050
l0 r, 00 M O N M V Ln W r, 00 M O M V In w n 00 0) O N M V In l0 r, 00 0) O M V Ln
N N N fV M M M M M M M M M M V 7 V V V V N fV N N M M M M M M M M M M v v v v v It
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 622
DRAFT edi VISTA`

DRAFT
■
Equipment and
Rebates/Cred 'its
2025 Natural Gas IRP Appendix 623
12 DRAFT 'eduVISTAa

DRAFT
Equipment Costs
• Assumes a 3-ton ducted heat pump is needed for space heat
(2,000 sq. ft. house)
• Full electrification cost for all appliances is assumed at $13, 162
(2024 $)*
• 3-ton ducted heat pump $5,993
Heat pump water heater $3,528
Electric Range $2,038
Electric Dryer $1 ,602
• Costs are assumed less incentives (IRA) and have a 5-year
payback period in the form of an average monthly payment
(annuity) at 3% interest
• Assumes a 20-year lifespan for all equipment (Heat pumps average
between 10-15 years on average)
*Electrifying Buildings — December 2022 rmi.org
2025 Natural Gas IRP Appendix 624
13 DRAFT edi VESTA`

DRAFT
IRA Rules
• Depending on income level , rebates for these home efficiency
upgrades can be as much as 100% of the costs, up to
$ 14,000
Maximum Allowed Rebate Amount Per Maximum Allowed Rebate Amount Per
Type of Home Energy Project Household Below 80%Area Median Household Above 80%Area Median
Income(AMI) Income(AMI)
Home Efficiency Project with at 50%of project costs, up to$2,000
least 20%predicted energy 80%of project costs, up to$4,000* (maximum of$200,000 for a multifamily
savings building)
Home Efficiency Project with at 50%of project costs, up to$4,000
least 35%predicted energy 80%of project costs, up to$8,000* (maximum of$400,000 for a multifamily
savings building)
Home Electrification Project 50%of project costs, up to technology
Qualified Technologies(only 100%of project costs up to technology cost maximums*; up to
households with an income belowcost maximums**; up to$14,000 $14,000 (households with incomes above
150%AMI are eligible) 150%AMI are not eligible)
2025 Natural Gas IRP Appendix 625
14 www.energy.gov DRAFT ed°I'VESTA

DRAFT
Input
2025 Natural Gas IRP Appendix 626
15 DRAFT ediIVISTA`

DRAFT
Weather
• RCP 4.5 weather is used at a daily level to estimate energy
needs by planning region .
• This is then rolled up to an average monthly level by end use
9000 6500
8500 Spokane k a n e 7500
p 6000 Roseburg 7000 Medford
8000
5500 6500
p 7500 N
5000 0 6000
7000 = 5500
Q 6500 i 4500 c 5000
c
6000 4000 Q 4500
Min/Mc.
5500 —8.5 8500 Min/Max(1950-2C 8500
000
Rolling
—Ro 1 math Falls —
4.5
5 8000 L a Grande —Rolling 20-4.5 —Historic Actual
� � rn ,, ; M Ln n rn I M 8000 —Rolling 20 year(HDD)
M M M 0 0 0 0 0 7 5 O O N N <
W W W 0 0 0 0 0 0 0 0 0 0 0 0 < _ _
N N N N N N 1 1 N N N N N N < A M 1—O M 1— W M
J1 — N N N N N c`'M(M M M M V V V
N 7500 70000000000000
Q 7000 NN N N N N N N N N N N NN
r ❑
6500
7000
c D
Q 6000 �
a 6500
5500
Min/Max(1950-2023) —4.5
5000 6000 Min/Max(1950-2023) —4.5
—8.5 =Historic Actual —8.5 —Historic Actual
Rolling 20-4.5 —Rolling 20 year(HDD)
4500 —Rolling 20-4.5 —Rolling 20 year(HDD)
Lor`rn M � — O �MLnI—O MNI- O MLor-rn c2025NaturalGaslRPAppendUO0 627
16 00000000 NNNNNMCMMM(MV 7V � r— O coI- O � M � I M � I- W M � r— W M � III
��mOooO0000000000000000000 DRAFT —'
T N N N N N N N N N N N N N N N N N N N N N N N 0 0 0 O O O O O N N N N N M M M M M V M V
0 6) 6) 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 4 VIS TA
N N N N N N N N N N N N N N N N N N N N N N N

DRAFT
COP including auxiliary
350%
—HP COP Combined COP
300
250%
200
o_
O
U
150%
100
50%
0%
-1 r- o cn Q0 M N Ln 00 .-I :I- r, o m 110 M N Ln 00 r-I -�t r� o fn (.0 M
r-I .-I r-I -1 N N N fM M M 4 �t �t -:T Ln Ln Ln LD lD l0 I*1 r� r� n
HDD
Assumes 100% efficient electric furnace as auxiliary backup heat
2025 Natural Gas IRP Appendix 628
17 DRAFT 'ediiV►STAa

DRAFT
Use per customer
La Grande
Space Heat
120
-Natural Gas (Therms) -Electric (Therm eq.)
100
80
Ln
C
v 60
t
H
40
20
0
lD w r` 00 CO M O O -1 N N M -zt �t Ln LD lD r\ 00 00 Ql O O I N N M :I- zt Ln
C Q C Q C Q Q C Q C Q C Q C Q C Q C Q
2025 Natural Gas IRP Appendix AW 629
DRAFT '°i V►SM

DRAFT
Daily Conversion to kWh
Washington Residential Medford Residential
Space Heat Space Heat
30.00 .00
25.00 25.00
20.00 20.00
E E
v `w
Y L
`w 15.00 a 15.00
d
s 3
Y
10.00 10.00
5.00 5.00
lD I� CO m O .--i N m 00 m O .--i N M V
N N N N N N N N N N N N N N N N N N N N
*29.3 kWh per therm of energy
2025 Natural Gas IRP Appendix 630
19 DRAFT edi VESTA`

DRAFT
Electr'If'Icat 'ion os
Estmimates
2025 Natural Gas IRP Appendix 631
20 DRAFT 'edu 1wmy'a

DRAFT Example with No Equipment Costs:
Levelized beginning in 2026
Levelized Cost La Grande
Res - Space Heat
$70.00
$60.00 $12.80 per month levelized
• Calculated at 20 year increments $50.00
• Includes inflation adjustment for each year $4000
o $30.00
• Current cost of capital is included in Q $20.00
levelized costs $10.00
• (6.71 % OR, 6.51 % WA) $
to N 00 O r-I M -ITN 00 O r-I f4 M V LnN N N " m m m M M m m M m M M M m M V V V � � V
• 0 0 0 0 rJ 0 " 0 0 " 0 rN (N " "This is done each year from 2026-2045 to
N N N N N N N N N N N N N N N N N N N N
estimate costs for space heating with heat Example with equipment costs:
pumps, heat pump water heater, and other 20 year levelized cost beginning in 2026
(range, dryer)
La Grande
Res - Space Heat
$70.00
$60.00 $35.31 per month levelized
$50.00
$40.00
v
o $30.00
a $20.00
$10.00
to r\ 00 Ol O r-I N M � Ln 1.0 r` 00 M O .--I N M � Ln
N N N N M M M M M M M M M M � � v IT � �
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix /�I. 632
21 DRAFT eu1IVISTA

DRAFT
Cost without equipment costs
• Per customer, per month , per end use, without appliance cost
$90.00 $90.00
—La Grande Res-Water Heat —La Grande Res-Space Heat
$80.00 —Klamath Falls Res-Water Heat $80.00 —Klamath Falls Res-Space Heat
$70.00 —Medford Res-Water Heat $70.00 —Medford Res-Space Heat
—Roseburg Res-Water Heat —Roseburg Res-Space Heat
$60.00 —WA Res-Water Heat $60.00 —WA Res-Space Heat
o $50.00 0 $50.00
(D a�
a $40.00 Q- $40.00
$30.00 $30.00
$20.00 $20.00
$10.00 $10.00
$0.00 $0.00
W ti 00 6) O N M le O W I-- 00 O O N M V O W Ih 00 C1 O N M qt O O ti CO O O N M qt O
N N N N M M M M M M M M M M I-T I-T v v v N N N N M M M M M M M M M M V le v le IT V
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 633
22 DRAFT �°Iv►STAff

DRAFT
Cost with equipment costs
$350.00 $250.00
-La Grande Res-Water Heat -La Grande Res-Space Heat
$300.00 -Klamath Falls Res-Water Heat -Klamath Falls Res-Space Heat
-Medford Res-Water Heat $200.00 -Medford Res-Space Heat
$250.00 -Roseburg Res-Water Heat -Roseburg Res-Space Heat
-WA Res-Water Heat -WA Res-Space Heat
o $200.00 r $150.00
L
d L
0. $150.0064
°'
$100.00
$100.00
---_.'...1/1/1--- -�---------------------------------
$50.00 $50.00
$0.00
O n 00 M O N M v 0 W I- M O O N M e 0 $0.00
N N N NM M M M M M M M M M V ; v v v v '0 r 00 (n O N M v N O 1- 00 M O N M v U.)O O O O O O O CD O CD CD CD O O O O N N N N M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
$450.00 -La GrandeCom-Space Heat
$700.00 -La Grande Com-Water Heat $400.00 -Klamath Falls Com-Space Heat
-Klamath Falls Com-Water Heat -Medford Com-Space Heat
$600.00 -Medford Com-Water Heat
$350.00 -Roseburg Com-Space Heat
-Roseburg Com-Water Heat -WA Com-Space Heat
$500.00 -WA Com-Water Heat $300.00
t $400.00 t $250.00
o G
a $300.00 $200.00
a
61) r� $150.00
$200.00 $100.00
$100.00
$50.00
$0.00 $0.00
C11 N N C4 O N M M M M M M M O N v v v <O N CO C1 O N M M N O M M M O N M V N
N N N N M M M M CD M M M M M V R CD CD CD V N N N N M M CD M M CD M M CD CM CD CD Co CD CD V
O O O O O C4 CD O O O O O C O O O O O O O O O O O O O O O O O O O O O O O Co O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix /II. 634
23 DRAFT J-dVISTA

DRAFT
Questions and/or
Feedback?
2025 Natural Gas IRP Appendix 635
24 DRAFT 'edu 1wmy'a

�ai'ISTA°
TAC 9 — 2025 Avoista Gas IRP
December 18, 2024

Agenda
• Peak Day
• NEI
• Alternative Fuel Prices
• Alternative Fuels Technical Potential Volumes (ICF)
• Daily Modeled Volumes
• All Resource Options
2025 Natural Gas IRP Appendix 637
�u/VISTa

MilestoneDate
12/18/2024 Today
11/19/2024 TAC 9
2025 Avista IRP Timeline 1/9/2025 TAC 10
1/22/2025 TAC 11
1/31/2025 IRP Draft to TAC
2/28/2025 IRP Draft Comments Due
4/1/2025 File IRP
2025 Gas IRP
Today TAC 10
IRP Draft to TAC
p TAC 11 IRP Draft Comments
T
Due File IRP
LO LO LO LO
N N N N N
O O O O O
N N N N N
00 00 C1 N
N r N M
r
TAC 10
Draft IRP Review-TAC
Finalize IRP
2025 Natural Gas IRP Appendix 638

Peak
2025 Natural Gas IRP Appendix 639
4 �iIVISTA®

Peak Day Calculation
• Used the 2026-2045 average growth rate from Load Forecast (AEG) to
adjust peak day with carbon intensity efficient of use per customer)
J p Y Y ( Y p )
• Expected customer counts from Load Forecast (AEG)
• Use 75t" percentile of historicalh winters HDD (2004-2023) for area
nonpeak days on Dec 20 and Feb 28 by area
• HDD peak days by area:
La Grande 73 HDD
Klamath Fall 71 HDD
Medford 60 HDD
Roseburg 53 HDD
Spokane 79 HDD
2025 Natural Gas IRP Appendix 640
III/VFSTa

Peak Day Calculation
Feb 28th Peak Dec 20th Peak
500,000 350.000
450,000 ■WA ■ID OR 300.000 ■WA ID OR
400,000
CU 350,000 � 250.000
CU 300,000
� 200.000
J o 250,000 o
200,000 LC150,000
Y
150,000 100.000
100,000 50.000
50,000 17 NR=[--7--M
O r` 00 O O r N M g 0 W r` 00 M O r N M1q LO 1O f- 00 CV N M 4 �
N N N N M M M M M M M M M M qI Iq qI IqqI it N N N N M M M co M M M M M M
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
System Peak
600,000
■WA ■ID ■LaGrande
500,000 Klamath Falls ■Roseburg ■Medford
400,000
0 300,000
200,000
100,000 Am
I I 1 11 11 11 1 1 1 1 1 1 1 ,NLW
cc r- co m O � N205-Natumi apsORFbAppanab � N cM -q Lo 641
N N N N M M M M r. h M M M Mq qt q qI qI qI /IIv_
O CDO O O O O O O O O O O CD CDO CDO O O ISTA®
N N N N N N N N N N N N N N N N N N N N

NEI
2025 Natural Gas IRP Appendix 642
�IIII��STa®

NEI* = example Econornic Indicators by Impact
Impact Employment Labor Income Value Added Output
1 - Direct 107.00 $4,186,318.69 $5,885,714.97 $18,488,622.00
2 - Indirect 26.91 $2,125,567.06 $3,456,331.04 $6,831,637.92
Inputs into I M PLAN 3 - Induced 29.02 $1,776,491.76 $3,170,463.10 $5,297,434.49
for capital requirement: Totals 162.93 $8,088,377.52 $12,512,509.12 $30,617,694.40
1 . State facility would reside: Oregon
2 . LFG Ca EX - $ 16 .4M Initial effects to a local industry
pDirect or Industries due to the activity
3 . Pipeline Cost - $2 .OM or policy being analyzed
Effects stemming from
Indirect business to business
Taxes purchases in the supply chain
taking place in the region
Sub County
Sub County Special Effects in the region stemming
Impact General Districts County a State Federal Total from households spending of
1 - Direct $ 78,676 $ 124,057 $ 48,363 $ 336,474 $ 900,835 $ 1,488,405 Induced p g
2 - Indirect $ 52,120 $ 82,183 $ 32,266 $ 187,818 $ 504,647 $ 859,034 income, after removal of taxes,
3 - Induced $ 42,267 $ 66,647 $ 26,681 $ 160,234 $ 436,411 $ 732,240
Total Impact $ 173,062 $ 272,886 $ 107,310 $ 684,526 $ 1,841,894 $ 3,079,679 savings, and commuters
2025 Natural Gas IRP Appendix 643
8 *Also Including Safety Incidents and Carbon Monoxide Poisoning rduVISTA®

Alternat 'ive u e ri ces
2025 Natural Gas IRP Appendix 644
'edIII/onSTaa

Alternative Fuel Prices Inputs
Model Restriction Capital Costs
L L
• Selection for any physical
• Equipment
products will not be available in
p • Pipeline Costs
the model until 2030 • Installation and Owners Costs
• Avera e rices above 75 er O&M Fid and Variable
g p � p
Dth will not be modeled • Electricity rates
• Gas rates
2025 Natural Gas IRP Appendix 645
'eIIII1f STA®

Prices
• Expected prices are broken down between northwest and national
technical potential (ICF)
• All prices consider Inflation Reduction Act (IRA) incentives where applicable
• These prices assume a first mover access to alternative fuels
• Prices are averaged between two distinct groupings Northwest and National to
reduce model inputs
• Hydrogen (1-12) & Synthetic Methane (SM) prices will be treated as a purchase gas
agreement where Avista would sign a term contract, each year, with the producer
for these prices through the forecast.
• Renewable Natural Gas assumes a proxy ownership with costs levelized over 20
years
• Renewable Thermal Credit (RTC) is a production cost plus, where prices cover all
costs
• These exclude Investment Tax Credit (ITC) or Production Tax Credit (PTC) and consider
a higher capital rate
• Prices are nominal and levelized for each reference year
2025 Natural Gas IRP Appendix 646
11 �uVISTA

Hydrogen ( H2) and Synthetic Methane (SM )
Hydrogen Synthetic Methane
$100.00 $100.00
$ 0.00 Blue Hydrogen 1 Biomass 1
Green H2-Wind+Electrolysis 1 $90.00 Biomass 2
$80.00 GreenH2-Solar+Electrolysis 1 Biomass 3
Microwave Pyrolysis 1 G $80.00
a $70.00 L $70.00 Green H 2-B iogen icCO2 1
d
$60.00 a
$60.00
$50.00
E $40.00 £ $50.00 _
O O $40.00
Z $30.00
Z
$20.00 _r $30.00
$10.00 $20.00
$_ $10.00
Col.- 00 O O � N M 14 LOW 1­ 00 (n O r N M � LO
$-
0 0 0 O O O O O O O O O O O O O O O O O (O � OD M O r N M � LOW I,- 00 O O � N M .1 W
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M Iq 11 111*
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
ICF levelized the Section 45V tax credit over 20 years. Since hydrogen
projects must be under construction by the end of 2032 to qualify for
45V credits, the 45V tax credits were modeled until 2035 as a
conservative estimate assuming every new hydrogen facility beginning
construction after 2032 may not qualify for the tax credit. ICF assumed
EAC requirements and other requirements for 45V credits are met to
minimize the CI which doesn't include embodied emissions and receive
the maximum credit amount of $3/kg.
2025 Natural Gas IRP Appendix 647
12 'AI�IIVISTAW

Renewable Natural Gas (RNG)
RNG - Low $ Feedstock RNG - Higher $ Feedstock
$35.00 RNG -LFG 2 RNG -LFG 3 $100.00 g
s $30.00 RNG -LFG 4 RNG -LFG 5 $90.00
p RNG -WW 3 RNG -WW 4
a $25.00 RNG -WW 5 p $80.00
Q $70.00 i
$20.00 $60.00
$50.00
o $15.00
Z o $40.00
$10.00 Z
$30.00
$20.00
$5.00
$10.00 RNG -AM 4 — RNG -AM 5 —RNG -FW 3
RNG -LFG 1 RNG -WW1 RNG -WW2
CO 1.- CO CA O N M -It to CO 1-- CO O1 O r N M ICT LO CO 1- 00 O) O � N M IRT 0 CO 1.- W O O N M 11 N
N N N N M M M M M M M M M M 0 0 CD CD (D CD N N N N M M M M M M M M M M 0 0 0 CD CD CD
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
*Blend of national and NW estimated costs for RNG fa¢mlili[�sral Gas ARP Appendix 648
13 **Includes ITC/PTC until 2030 AMESTA®

Renewable Thermal Certificate (RTC)
RTC - Low $ Feedstock RTC - Higher $ Feedstock
$50.00 $160.00
s $140.00
p $40.00 p
$120.00
Q
$30.00 $100.00
c = $80.00 �_
Z $20.00 Z $60.00
$10.00 RTC (RNG -LFG 2) RTC(RNG-LFG 3) $40.00
RTC (RNG -LFG 4) RTC(RNG-LFG 5) RTC (RNG -AM 4) — RTC (RNG -AM 5)
RTC (RNG -WW 3) RTC(RNG-WW 4) $20.00 RTC (RNG -FW 3) — RTC (RNG -LFG 1)
$- RTC RNG -WW 5 $- RTC (RNG -WW 1) RTC (RNG -WW 2)
to r­ 00 0) O r N M .4 M O ti 00 C> O r N M 't LO CO h 00 0) O r N M qt 07 W I- CO Cn O r N M le 1A
N N N N M M M M M M M M M M I Iq qt qt It N N N N M M M M M M M M M M qt qt It It It le
O O O O O O O O O O O O CDOCDOO O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1-No ITC, considers price from producer to create RTC and cover cos;92t @t�dh"m§` 649
14
2-Not tied to market actual prices ���iVISTA®

Carbon Capture , Utilization and Storage (CCUS)
$50.00
$45.00 under 25 Dth/hr- $1,000
Industrial CCUS $900
$40.00 25-50 Dth/hr- under 25 Dth/hr-
$35.00 Industrial CCUS O $800 Industrial CCUS
U $700 25-50 Dth/hr-
$30.00 50-100 Dth/hr- Industrial CCUS
Industrial CCUS 2 $600 50-100 Dth/hr-
a $25.00ilillillwaso�
100-200 Dth/hr- a) Industrial CCUS
to, 1111111 a $500
� $20.00 Industrial CCUS � 100-200 Dth/hr-
$400 Industrial CCUS
$15.00 200-400 Dth/hr- c
p Industrial CCUS $300 200-400 Dth/hr-
Z $10.00 C Industrial CCUS
$5.00 800-1600 Dth/hr- Z $200 800-1600 Dth/hr-
Industrial CCUS Industrial CCUS
$- Direct Air Capture- $100 Direct Air Capture-
CO 000rno NMleLO (D [­ 000) o NMleLn DAC CCUS DAC CCUS
N N N N Cl) M M M M M M M M M 11 11 NT 11 11 � $"
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (O 1*- 00 0) O N M 1* Ln (O 1-- 00 0) O N M I LO
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M It 11 qe q1 11q4'
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Avista specific high-volume customers 2025 Natural Gas IRP Appendix 650
15 �iIVISTA�
**Includes ITC/PTC to 2030

Alternative Fuels Technical Potential Volumes
( ICF)
2025 Natural Gas IRP Appendix 651
�IIIIV�STa

Volumes
• Expected volumes are broken down between Northwest and
national technical potential
These volumes assume a first mover access to alternative fuels
• Weighted by US population for states where some form of climate
policy is in place or demand is expected
• Modeled potential volumes are from Avista's weighted share in only
the Northwest for RNG, H2, SM
• Broken out by 2023 number of meters between LDCs in Oregon and
Washington
Company 2023#of Meters Share
AVA 379,223 15.831%
CNG 316,929 13.231%
NWN 799,250 33.366%
PSE 900,000 37.572%
Total NW 2,395,402 100.000%
20,25 Natural Gas IRPA Pe dix 652
17 *Renewable Energy Technical Potential - The renewable energy technical potential o? a technology is its achievable energy generation given di7 _ISTA�
system performance, topographic, environmental, and land-use constraints.
�uiV

H2 and SM - Avista's share
Technical Potential Volumes (2026=2045)
140 120
120 100 0
100
■ Blue Hydrogen ■ Biomassl
80
s o t o
80 0 Green H2-Wind 0
0 0 +Electrolysis 0 0 ■ Biomass2
N a 60
0 GreenH2-Solar 0 0
0 ❑ 0 ❑ Biomass3
60 +Electrolysis
Microwave Pyrolysis 40 GreenH2-
40 0 BiogenicCO2
20 20 0
o c �
*H2 will be limited by volume to 20% 2025 Natural Gas IRP Appendix /I�■ 653
18 **No volumes will be available until 2030

RNG - Avista's Share
Technical Potential Volumes (2026=2045)
160 2.50
140
2.00
120
■ RNG -WW1
0 100 X t
■ RNG -AM4 0 1.50 X ■ RNG -WW2
0 0
c 80 ■ RNG -AM5 RNG -WW3
0 2
60 ■ RNG -FW = 1.00 ■ RNG -WW4
■ RNG -WW5
40 X
0.50
20
0.00
40
35
30
A RNG -LFG1
0 25
■ RNG -LFG2
0
Cn 20 MI RNG -LFG3
0
.2 15 ■ RNG -LFG4
❑ RNG -LFG5
10
5
2 5 Natural Gas IRP Appendix 654
19 *Quantities not available until 2030 'ediI Iffsma

RTC* - Avista's Share
Technical Potential Volumes (2026=2045)
4.00
45
3.50
0
40 0
0 3.00
35
■ RTC -WW1
2.50
L 30 ■ RTC WW2
■ RTC -AM4 o
0
0 25 2.00 0 RTC -WW3
N � O
■ RTC AM5 _ 1.50 El RTC WW4
20 ❑ RTC FW3 ■ RTC WW5
15 0 1.00
10 0.50
5 0.00
120
100
t 80 ■ RTC-LFG1
■ RTC-LFG2
0
6r ■ RTC-LFG3
■ RTC-LFG4
� qr
■ RTC-LFG5
2025 Natural Gas IRP Appendix 655
20 *Quantities are available to the model in 2026 'edu ormsma

CCUS
Industrial CCUS Direct Air Capture CCUS
180,000
1,800,000
160,000
1,600,000
140,000
1,400,000
120,000
1,200,000
O 100,000
Q 80,000 O 1,000,000
60,000 Q g 800,000
40,000 ��
�� 600,000
20,000
400,000
25-50MMBtu/hr 100-200MMBtu/hr 800-1600MMBtu/hr 200,000
under 25MMBtu/hr 50-100MMBtu/hr 200-400MMBtu/hr
*Years 2025-2045 2025 Natural Gas IRP Appendix Allen 656
21 ,,No Volumes will be available until 2030 454MISTA®

Daily Modeled Volumes
2025 Natural Gas IRP Appendix 657
�IIII��STa®

H2 - Modeled Volumes
Daily Volumes Annual Volumes
800,000
Available in CROME 350,000,000
700,000
600,000 300,000,000
0 500,000 250,000,000
L
CL 400,000Mai
0 200,000,000
p 300,000
150,000,000
200,000 Q
100,000 100,000,000
50,000,000
(fl ti CO O O N M -* LO CD h 00 O) O � N M LO
N N N N M M M M M M M M M M CD CD CD 0 CD 0
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N _
CG h 00 M O � N M � In t0 1� 00 O O � N M � Lt7
Blue Hydrogen 1 Green H2-Wind+Electrolysis 1 GreenH2-Solar+Electrolysis 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
*H2 will be limited by volume to 20% regardless of availability 2025 Natural Gas IRP Appendix 658
23 **No volumes will be available until 2030 AMISTA`

SM - Modeled Volumes
Daily Volumes Annual Volumes
350,000 120,000,000
Available in CROME
300,000 100,000,000
250,000
m 200,000 s 80,000,000
0 0
CL 150,000 60,000,000
s_ c
c
100,000
Q 40,000,000
50,000
- 20,000,000
N N
i
N CO O CDr N M Cn In O I- CO O CDr N M I N
N N N M M M M M M M M M M CD 0 0 'Cr CD CD
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N -
W h W O O r N M In fD h W O O r N M U')
N N N N M M M M M M M M M M 0 CI 0 CD 0 CD
Biomass 1 Biomass 2 Biomass 3 Green H2-BiogenicCO2 1 N N N N N N N N N N N N N N N N N N N N
*SM is limited to NW Technical Potential availability &Avista share bA1 j9;ai#RfijpQpemQters 659
24 **No volumes will be available until 2030 AMISTA®

RNG - Modeled Volumes
Daily Volumes Annual Volumes
16,000 6,000,000
14,000 Available in CROME _ _ _
_ — 5,000,000
12,000
— 4,000,000
M 10,000 - - o
L
Q 8,000 _ _ 3,000,000
c
0 6,000 4,000 2,000,000
' ' '
2,000 , ' ■ ■ ■ • , , , ' 1,000,000 LI
M M E 110 r
to I- W M O r N M Ile M W I- O M O r N M IRT 0 CO h CO M O r N M 'Cr N W 1- W M O r N M 0
N N N N M M M M M M M M M M ICT ICT le le Ile Ile N N N N M M M M M M M M M M Iq 'Cr Iq
O O O O O O O O O O O O O O O O O O O O o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
RNG -AM 4 RNG -AM 5 RNG - FW 3 ■RNG - LFG 1 RNG - LFG 2
RNG - LFG 3 ■RNG - LFG 4 RNG - LFG 5 RNG -WW1 RNG -WW 2
RNG -WW 3 RNG -WW 4 RNG -WW 5
*Quantities not available until 2030
25 **RNG volumes are limited to NW technical potential availability to alld8f4aT.,M /lT&PU8%teen RNG type ����660
***Removal of high priced RNG prior to modeling (AM1-3, FW1-2)

RTC - Modeled Volumes
Daily Volumes Annual Volumes
200,000 70,000,000
180,000
� w _ 60,000,000
160,000 � . � �
_ - 50,000,000
140,000
0
120,000 = 40,000,000
a 100,000
� 30,000,000
I 80,000 _ a
60,000 20,000,000
40,000 ' ■ ■ , , 10,000,000 ■
20,000 ■
■
W h W M O r N M * 0 W ti M M O r N M � U')
M Iq LO O ti O O O r• N M ll') N N N N M M M M M M M M M M N � � 14
N N N N M M M M M M M M M M I Iq � It Iq N N N N N N N N N N N N N N N N N N N N
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RTC(RNG-AM 4) RTC(RNG-AM 5) RTC(RNG-FW 3) ■RTC(RNG-LFG 1) RTC(RNG-LFG 2)
RTC(RNG-LFG 3) RTC(RNG-LFG 4) RTC(RNG-LFG 5) RTC(RNG-WW 1) RTC(RNG-WW 2)
RTC(RNG-WW 3) RTC(RNG-WW 4) RTC(RNG-WW 5)
*Quantities are available to the model in 2026
121
26 **RTCs are limited to National availability &Avista share and allocates y'K'M!�P��19Pv�Ffr�b24 Avista RFP volumes 'Ali.661
***Removal of high priced RTCs prior to modeling (AM 1-3, FW 1-2) AdVISTA®

CCUS
Daily Volumes Annual Volumes
120,000 Available in CROME 2,500,000
Industrial CCUS DAC
100,000
2,000,000
80,000 Ly
60,000 0 1,500,000
m �
CL
Q 40,000 1,000,000
20,000 a
500,000 M ■
CO ti CO O O N M It LO O I- CO O O r N M It LO
N N N N M CO M M M M M M M M Iq Iq RT Iq � Iq
O O O O O O O O O O O O O O O O O O O O -
N N N N N N N N N N N N N N N N N N N N to t` CO O O r N M 11 Ln LO I- 00 O O r N M 11 LO
N N N N M M M M M M M M M M 11 11 It qq q1 qt
■under 25 Dth/hr-Industrial CCUS ■25-50 Dth/hr-Industrial CCUS CD CD O CD CD CD CD CD CD CD CD CD CD CD O
050-100 Dth/hr-Industrial CCUS ■ 100-200 Dth/hr-Industrial CCUS N N N N N N N N N N N N N N N N N N N N
■200-400 Dth/hr-Industrial CCUS ■800-1600 Dth/hr-Industrial CCUS
■Direct Air Capture-DAC CCUS
*No Volumes will be available until 2030 2025 Natural Gas IRP Appendix 662 AM
27 **CCUS "Industrial" is based on Avista specific high-volume custom, STA®

Annual = Modeled Volumes vs . Technical Potential
Volumes
% of Modeled Volumes vs. Technical Potential** '/o of Modeled Total Volumes in CROME by Type*
°
14,000 5 100%
Technical Potential Total /o 'E (D
12 000 Modeled Available Volumes Total / 4% c E 90%
' Modeled % of Technical Potential 80%
cn 4% . o
0 10,000 4) 70%
3% v 0 60%
8,000 3% m 50%
6,000 2% 1 40%
�a o a�
= 4,000 2% a .2 30%
Q 1% 0 20%
2,000 1% 0 0 10%
0% 11
0% � tG f� O O O r N Ln Cfl I` 00 O O r N M � Ln
W1` 00M a CM M Iq OWI- OOMa NMqTO N N N N M M M M M M M M M M V V V V Iq Iq
N N N N M M M M M M M M M M ,* O O O O O O O O O O O O O O O O O O O O
0 0 0 M M 0 0 0 0 0 0 0 M 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N
NNNNNNNNNNNNNNNNNNNN ■ Hydrogen Synthetic Methane RNG RTC
*Excludes CCUS
**Technical Potential Volumes are from ICF and weighted to % share5o �a#iof customers for National and NW volumes in7 sss
28 �11iI/ISTA®
meaning this would be Avista s share of those volumes

All Resource Options
2025 Natural Gas IRP Appendix 664
�IIIIV�STa®

Propane Storage
• CapEX - $14.7MM (20 Year Asset Life) $175
• Plant Size — 30M Dth (1 cycle) $150
• Pipeline - $2MM $125
• Installation + Owners costs — 5% of capital o $100 Available in CROME
cost `
a $75
• Delivery Cost - $0.33 per gallon of Propane
$50
• Plant electricity and air injection E
• Siting, permitting and build - 2 years Z $25
• Propane costs per gallon are included in tfl1� 00MCrNMMLC� MMMMCrNM � Lll
N N N N M M M M M M M M M M � � � � � �
estimated nominal $ per Dth
N N N N N N N N N N N N N N N N N N N N
*Cycling of plant reduces overall cost per Dth 2025 Natural Gas IRP Appendix ■ 665
�/��ui
30 **No volumes will be available until 2028 1n.5m ®

Liquified Natural Gas ( LNG) Peak Storage
• CapEX - $200MM (50 Year Asset Life —
Avista Rev. Req)
$40.00
• Plant Size — 1 .037MM Dth
$35.00
• Max volume per day — 103,700Dth
s $30.00
• Pipeline - $2MM o
L $25.00 Available in CROME
• Utility Interconnect - $3. 12MMCL $20.00
Vil
• Installation + Owners costs — 30% of capital o $15.00
• Liquefaction Costs Z $10.00
• Days of peak supply — 10 $5.00 —LNG Peaker Plant
• Liquefier capacity per day — 7,000 Dth $_
•
Siting, permitting and build - 4years 000O0000000000000000
N N N N N N N N N N N N N N N N N N N N
• Gas commodity costs included in CROME
and combined with estimated nominal $ per
Dth
*Cycling of plant reduces overall cost per Dth 2025 Natural Gas IRP Appendix ���� 666
31 **No volumes will be available until 2030 �uiVISTA®

Constraints of Resource options in CROME
Resource •e F'--Eu- Volurnetric Restrictionof Availability
Allowances 10% of Market per program rules (CCA) 2026
Community Climate Investments 15% (2025-2027), 20% 2028+ (CPP) 2026
Demand Response CPA from AEG for potential 2026
Electrification No constraints, up to total energy demanded on 2026
LDC by area/class/year
Energy Efficiency CPA from AEG and ETO 2026
Renewable Thermal Credit 2026
NW Technical Potential (ICF)
Propane Storage 30,000 Dth 2028
Hydrogen NW Technical Potential to Avista (ICF) & 20% by 2030
volume
Synthetic Methane NW Technical Potential to Avista (ICF) 2030
Renewable Natural Gas NW Technical Potential (ICF) for allocation of 2030
1.5MM Dth Total Availability
Liquified Natural Gas 1 Bcf Total & 0.1 Bcf Daily W/D 2030
Carbon Capture, Utilization and Storage 2030
ConstrairdS5 �AWAtr�t ;Xvolume customers (ICF) 667
32 A', TA®

Remaining TAC Meetings
TAC 10 — (January 9t") TAC 11 — (January 22nd)
• Conservation Potential Assessment (AEG) • Risks and costs by scenario
• Demand Response Potential Assessment (AEG) • Preferred Resource Selection
• Conservation Potential Assessment (ETO) • Non-Energy Impacts
• Dual Fuel Pilot Program — Oregon (ETO) • Emissions by Scenario
• Deterministic Results • Energy Burden
• Alternative Fuel Final Results - Questions • Average Rates
• Net present value revenue requirement (NPVRR)
• Action Items
2025 Natural Gas IRP Appendix 668
33 *Draft will be released on or before January 31 , 2025 ard°l—VIS

�iivlSTA'
TAC 10 — 2025 Avoista Gas I RP
Edited Alternative Fuel Volumes

Alternat 'ive u e ri ces
2025 Natural Gas IRP Appendix 670
III/Insma

Alternative Fuel Prices Inputs
Model Restriction Capital Costs
L L
• Selection for any physical
• Equipment
products will not be available in
p • Pipeline Costs
the model until 2030 • Installation and Owners Costs
• Avera e rices above 75 er O&M Fid and Variable
g p � p
Dth will not be modeled • Electricity rates
• Gas rates
2025 Natural Gas IRP Appendix 671
'eIIII1f STA®

Prices
• Expected prices are broken down between northwest and national
technical potential (ICF)
• All prices consider Inflation Reduction Act (IRA) incentives where applicable
• These prices assume a first mover access to alternative fuels
• Prices are from the Northwest for each alternative fuel and National for Renewable
Thermal Credits (RTC)
• Hydrogen (1-12) & Synthetic Methane (SM) prices will be treated as a purchase gas
agreement where Avista would sign a term contract, each year, with the producer
for these prices through the forecast.
• Renewable Natural Gas (RNG) assumes a proxy ownership with costs levelized
over 20 years
• RTC considers a production cost plus, where prices cover all costs
• These exclude Investment Tax Credit (ITC) or Production Tax Credit (PTC) and consider
a higher capital rate
• Prices are in nominal dollars
2025 Natural Gas IRP Appendix 672
"ir-u/VISTa

Hydrogen ( H2) and Synthetic Methane (SM )
Hydrogen Synthetic Methane
$100.00 $100.00
$ 0.00 Blue Hydrogen 1 Biomass 1
Green H2-Wind+Electrolysis 1 $90.00 Biomass 2
$80.00 GreenH2-Solar+Electrolysis 1 Biomass 3
Microwave Pyrolysis 1 G $80.00
a $70.00 L $70.00 Green H 2-B iogen icCO2 1
d
$60.00 a
$60.00
$50.00
E $40.00 £ $50.00 _
O O $40.00
Z $30.00
Z
$20.00 _r $30.00
$10.00 $20.00
$_ $10.00
Col.- 00 O O � N M 14 LOW 1­ 00 (n O r N M � LO
$-
0 0 0 O O O O O O O O O O O O O O O O O (O � OD M O r N M � LOW I,- 00 O O � N M .1 W
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M Iq 11 111*
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
ICF levelized the Section 45V tax credit over 20 years. Since hydrogen
projects must be under construction by the end of 2032 to qualify for
45V credits, the 45V tax credits were modeled until 2035 as a
conservative estimate assuming every new hydrogen facility beginning
construction after 2032 may not qualify for the tax credit. ICF assumed
EAC requirements and other requirements for 45V credits are met to
minimize the CI which doesn't include embodied emissions and receive
the maximum credit amount of $3/kg.
2025 Natural Gas IRP Appendix 673
�IIIIVISTAW

Renewable Natural Gas (RNG)
RNG - Low $ Feedstock RNG - Higher $ Feedstock
$35.00 RNG -LFG 2 RNG -LFG 3 $100.00 g
s $30.00 RNG -LFG 4 RNG -LFG 5 $90.00
p RNG -WW 3 RNG -WW 4
a $25.00 RNG -WW 5 p $80.00
Q $70.00 i
$20.00 $60.00
$50.00
o $15.00
Z o $40.00
$10.00 Z
$30.00
$20.00
$5.00
$10.00 RNG -AM 4 — RNG -AM 5 —RNG -FW 3
RNG -LFG 1 RNG -WW1 RNG -WW2
CO 1.- CO CA O N M -It to CO 1-- CO O1 O r N M ICT LO CO 1- 00 O) O � N M IRT 0 CO 1.- W O O � N M 11 N
N N N N M M M M M M M M M M 0 0 CD CD (D CD N N N N M M M M M M M M M M 0 0 0 CD CD CD
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
*Blend of national and NW estimated costs for RNG faCiMiOsral Gas ARP Appendix 674
s **Includes ITC/PTC until 2030 'A VISTAW

Renewable Thermal Certificate (RTC)
RTC - Low $ Feedstock RTC - Higher $ Feedstock
$50.00 $160.00
s $140.00
p $40.00 p
$120.00
Q
$30.00 $100.00
c = $80.00 �_
Z $20.00 Z $60.00
$10.00 RTC (RNG -LFG 2) RTC(RNG-LFG 3) $40.00
RTC (RNG -LFG 4) RTC(RNG-LFG 5) RTC (RNG -AM 4) — RTC (RNG -AM 5)
RTC (RNG -WW 3) RTC(RNG-WW 4) $20.00 RTC (RNG -FW 3) — RTC (RNG -LFG 1)
$- RTC RNG -WW 5 $- RTC (RNG -WW 1) RTC (RNG -WW 2)
to r­ 00 0) O r N M .4 M O ti 00 C> O r N M 't LO CO h 00 0) O r N M qt 07 W I- CO Cn O r N M le 1A
N N N N M M M M M M M M M M I Iq qt qt It N N N N M M M M M M M M M M qt qt It It It le
O O O O O O O O O O O O CDOCDOO O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1-No ITC, considers price from producer to create RTC and cover cos;92t @t4dh"m§` 675
7
2-Not tied to market actual prices ���iVISTA®

Carbon Capture , Utilization and Storage (CCUS)
$50.00
$45.00 under 25 Dth/hr- $1,000
Industrial CCUS $900
$40.00 25-50 Dth/hr- under 25 Dth/hr-
$35.00 Industrial CCUS O $800 Industrial CCUS
U $700 25-50 Dth/hr-
$30.00 50-100 Dth/hr- Industrial CCUS
Industrial CCUS 2 $600 50-100 Dth/hr-
a $25.00ilillillwaso�
100-200 Dth/hr- a) Industrial CCUS
to, 1111111 a $500
� $20.00 Industrial CCUS � 100-200 Dth/hr-
$400 Industrial CCUS
$15.00 200-400 Dth/hr- c
p Industrial CCUS $300 200-400 Dth/hr-
Z $10.00 C Industrial CCUS
$5.00 800-1600 Dth/hr- Z $200 800-1600 Dth/hr-
Industrial CCUS Industrial CCUS
$- Direct Air Capture- $100 Direct Air Capture-
CO 000rno NMleLO (D [­ 000) o NMleLn DAC CCUS DAC CCUS
N N N N Cl) M M M M M M M M M 11 11 NT 11 11 � $"
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (O 1*- 00 0) O N M 1* Ln (O 1-- 00 0) O N M I LO
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M It 11 qe q1 11q4'
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Avista specific high-volume customers 2025 Natural Gas IRP Appendix 676
$ �iIVISTA�
**Includes ITC/PTC to 2030

Alternative Fuels Technical Potential Volumes
( ICF)
2025 Natural Gas IRP Appendix 677
�IIIIV�STa

Updated Technical Potential Volumes
• Total Technical Potential Volumes have been updated from the final
version of TAC 9 (12/18/2024)
• These volumes were overestimated based on interpretations of
math provided by ICF
Clarification was given by ICF on January 3rd and Impacted deterministic runs
- The "output Excel files list a unit of 1x10e9 Btu for various resources. This is equivalent to
billion Btu. If one were to enter 1x10E9 into an Excel file, you will get 10 billion
10,000,000,000). However, this is because the number should be interpreted as 1x109. The
`e" is meant to stand for "exponent"whereas entering the sequence 10E9 in Excel is
interpreted as 10 x 10 .
The good news is the final number matched closely to those Avista
adjusted for estimated volumes, so now all volumes for alternative fuels
are from ICF study directly
• These deterministic alternative scenarios will be reviewed along with final
content in TAC 11
The deterministic PRS will be discussed further in TAC 10
2025 Natural Gas IRP Appendix 678
'eIIII o/'lSTa®

Volumes
• Expected volumes are broken down between Northwest and National
technical potential
These volumes assume a first mover access to alternative fuels
• Weighted by US population for states where some form of climate policy is in
place or demand is expected
Modeled physical potential volumes are from Avista's weighted share in the
Northwest and intended to represent all volumes available to Avista in the
United States
RTC are the only National potential volumes considered and assumes physical
pipeline accessibility to meet CCA and CPP program rules
Broken out by 2023 number of meters between LDCs in Oregon and Washington
Company 2023#of Meters Share
AVA 379,223 15.831%
CNG 316,929 13.231%
NWN 799,250 33.366%
PSE 900,000 37.572%
Total NW 2,395,402 100.000%
20 5 Natu al Gas IRPA pe dix 679
11 *Renewable Energy Technical Potential - The renewable energy technical potential o? a technology is its achievable energy generation given _ _
system performance, topographic, environmental, and land-use constraints.
AuiVISTA

Hydrogen - Avista's Share
Technical Potential Volumes (2026=2045)
70
60
50
40 p _
0
30
s
20 _
10
W r` CO 0) O N M IqT LO O r` 00 0) O N M 11 LO
N N N N M M M M M M M M M M IRT q* 1* 1* 11 Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Blue Hydrogen National Blue Hydrogen NW Green H2-Wind+Electrolysis National
Green H2-Wind+Electrolysis NW GreenH2-Solar+Electrolysis National Green H2-Solar+Electrolysis NW
■Microwave Pyrolysis National Microwave Pyrolysis NW Plasma Pyrolysis National
Plasma Pyrolysis NW Thermal Pyrolysis National Thermal Pyrolysis NW
*H2 will be limited by volume to 20% 2025 Natural Gas IRP Appendix �■ 680
12 **No volumes will be available until 2030 e/�uiVISTA`

Synthetic Methane - Avista's Share
Technical Potential Volumes (2026=2045)
1,200
1,000
800
N
0 600
a
400
a�
0 200
1 1
c0 ti CO M O N M It 0 cD ti 00 M O N M 0
N N N N M M M M M M M M M M le 11 It 11 V 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
■Biomass National Biomass NW
■Green H2-BiogenicCO2 National GreenH2-BiogenicCO2 NW
GreenH2-CCS National GreenH2-CCS NW
■GreenH2-DAC National ■GreenH2-DAC NW
■PinkH2-National-BiogenicCO2 National ■PinkH2-National-CCS National
■PinkH2-National-DAC National ■PinkH2-NW-BiogenicCO2 NW
■PinkH2-NW-CCS NW PinkH2-NW-DAC NW
2025 Natural Gas IRP Appendix 681
13 *No volumes will be available until 2030 �iIVISTA

Renewable Natural Gas - Avista's Share
Technical Potential Volumes (2026=2045)
70
60
50
N
C
0 40
30
m
t ,
o _ r
20
10
ti CO M O N M qq LO to ti 00 M O N M It U1
N N N N M M M M M M M M M M I It 11 It 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG -AM National RNG -AM NW RNG - FW National RNG - FW NW
RNG - LFG National RNG - LFG NW ■RNG -WW National RNG -WW NW
2025 Natural Gas IRP Appendix 682
14 *No volumes will be available until 2030 �iIVISTA®

Renewable Thermal Certificate - Avista's Share
Technical Potential Volumes (2026=2045)
45
40
35
30
c
25
20
a
m
0 15
10
5
A
t0 � CO M O r N M � LO CC N. 00 M O r N M I Ln
N N N N M M M M M M M M M M It It Iq 11 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG (National) -AM National RNG (National) - FW National
RNG (National) - LFG National RNG (National) -WW National
2025 Natural Gas IRP Appendix 683
15 *Volumes are available to the model in 2026 edu VISTA`

CCUS (2026=2045)
2.50
Direct Air Capture-DAC CCUS
2.00 (1 MTCO2e Reduction eq) (blank)
800-1600MMBtu/hr-Industrial
CCUS (1 MTCO2e Reduction eq)
U) (blank)
■200-400MMBtu/hr-Industrial
0 1.50
CCUS (1 MTCO2e Reduction eq)
(blank)
100-200MMBtu/hr-Industrial
N CCUS (1 MTCO2e Reduction eq)
0 1.00 (blank)
50-100MMBtu/hr-Industrial CCUS
(1 MTCO2e Reduction eq) (blank)
I 25-50MMBtu/hr-Industrial CCUS
0.50 (1 MTCO2e Reduction eq) (blank)
■ 2 MMB hr-In ri under 5 tu/ dustI a
1 1 1 1 1 1 1 1 1 1 CCUS (1 MTCO2e Reduction eq)
e e e e (blank)
0.00
O ti CO O O r N M It LO W 1` 00 O O r N M le LO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Years 2025-2045 2025 Natural Gas IRP Appendix �■ 684
16 **No Volumes will be available until 2030 e/�u1VISTA`

Daily Modeled Volumes
2025 Natural Gas IRP Appendix 685
�IIII��STa®

H2 - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
100,000 35
■Blue Hydrogen 1
90,000 ■Green H2-Wind+Electrolysis 1 N 30
■Green H2-Solar+Electrolysis 1
80,000 -Microwave Pyrolysis 1 O
R 70,000 25
60,000 20
sCr
50,000
° 40,000 15
30,000
10
20,000 C
10,000 Q 5
tD 1N M O O N M In M M M M O N M In
N N N N M M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*H2 will be limited by volume to 20% regardless of availability 2025 Natural Gas IRP Appendix 686
18 **No volumes will be available until 2030 AMISTA`

SM - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
25,000 10
9
20,000 0 8
7
15,000 6
� a 5
10,000 4
o �
3
5,000 2
- Q 1 � ■ 1 1
N N N N M M M M M M M M M M CO 1` QQ a) CD N M � 0 CO I,- Co a) O NM It 0
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o N N N N M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
Biomass 1 Biomass 2 Biomass 3 Green H2-BiogenicCO2 1
*SM is limited to NW Technical Potential availability &Avista share bAWdQf3j8RfijpQpeffl hers 687
.0
19 **No volumes will be available until 2030 VISTA®

RNG - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
14,000 6
12,000 — N
• o
5
10,000
- 4
8,000 '
Cr 3
6,000
4,000 2� ' � �
2,000 1 ' ■ ■ ' ' Q 1
O O O O O O O O O O O O O O O O O O O O N N N N M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG -AM 4 RNG -AM 5 RNG - FW 3 ■RNG - LFG 1 RNG - LFG 2
RNG - LFG 3 ■RNG - LFG 4 RNG - LFG 5 RNG -WW 1 RNG -WW 2
RNG -WW 3 RNG -WW 4 RNG -WW 5
*Quantities not available until 2030 2025 Natural Gas IRP Appendix 688
20 **Removal of high priced RNG prior to modeling (AM1-3, FW1-2) �iIVISTA®

RTC - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
100,000 ' ` 40
90,000 _ - v, 35
80,000 r-
•° 30
70,000
60,000 _ 25
� I I
CL 50,000 _ 20
0 40,000
30,000 _ — ' ' ' 15
I
20,000 10 �
10,000 _ ■ ■ ' a 5
-
0 0 0 o a a a a a a a a a a o 0 0 0 0 o to ti 00 M O N MIRT LO (0 ti 00 M O N M 11 LO
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M
RTC(RNG-AM 4) RTC(RNG-AM 5) RTC(RNG-FW 3) ■RTC(RNG-LFG 1) RTC(RNG-LFG 2) O O O O O O O O O O O O O O O O O O O O
RTC(RNG-LFG 3) RTC(RNG-LFG 4) RTC(RNG-LFG 5) RTC(RNG-WW 1) RTC(RNG-WW 2) N N N N N N N N N N N N N N N N N N N N
RTC(RNG-WW 3) RTC(RNG-WW 4) RTC(RNG-WW 5)
*Quantities are available to the model in 2026 2025 Natural Gas IRP Appendix 689
21 **Removal of high priced RTCs prior to modeling (AM 1-3, FW1-2) .A VISM

CCUS
NW Only
Daily Volumes Annual Volumes (MTCO2e)
Available in CROME 2,500,000
7,000 Industrial CCUS ■DAC
6,000
2,000,000
5,000
N
0 4,000
L 0 1,500,000
a 3,000
0 2,000 = 1,000,000
c
1,000 Q
500,000
CG h 00 O) O N M 1* LO CO r 00 O O N M LO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
under 25MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) 25-50MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) W ti 00 M O r N CO q* LC) W ti 00 0) O r N M q* Lf)
50-100MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) 100-200MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) N N N N M M M M M M M M M M leqCt q* V q1 qe
O O O O O O O O O O O O O O O O O O O O
200-400MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) 800-1600MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) N N N N N N N N N N N N N N N N N N N N
■Direct Air Capture-DAC CCUS(1 MTCO2e Reduction eq)
*No Volumes will be available until 2030 2025 Natural Gas IRP Appendix 690
22 **CCUS "Industrial" is based on Avista specific high-volume custom, AMISTA`

Annual = Modeled Volumes vs . Technical Potential
Volumes
% of Modeled Volumes vs. Technical Potential** % of Modeled Available Volumes in CROME by Type*
1,400 Technical Potential Total 12% 100% I
■ Modeled Available Volumes Total d 90%
1,200 — Modeled %of Technical Potential °
10/o ca 80%
c a 70%
9 1,000 8% v Q 60%
s 800 c 40%
600 0 30%
4% O 20%
Q 400 _d o 10%
� o
2% 0 0%
2OO I 0 CG 1I- OD O O N M Iq O to 1- 00 0) O � NM 11 O
- N N N N M M M M M M M M M M I* I* I* I* q* N*
• N N N N N N N N N N N N N N N N N N N N
_ o
CO1- 00 0) OrNMleOOti00OO NM � 0o CCUS (Dtheq) H2 RNG RTC SM
O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N
*Technical Potential Volumes are from ICF and weighted to % shaw2efvL of 4�aers for National and NW volumes, 691
23 meaning this would be Avista's share of those volumes 'ediI Vasma

Other Supply Side Resource Options
2025 Natural Gas IRP Appendix 692
�IIIIV�STa�

Propane Storage
• CapEX - $14.7MM (20 Year Asset Life) Available in CROME
$225
• Plant Size — 30M Dth (1 cycle) $200 i Fixed Costs ■Variable Costs
• Installation + Owners costs — 5% of capital $175
cost
$150
• Delivery Cost is included $125
• Plant electricity and air injection .o $100
• Siting, permitting and build - 2 years Z $75
$50
• Propane costs per gallon are included in $50
estimated nominal $ per Dth — Variable $_
Costs N N N N M M M CO) M LO M M M M M CD Cq CO) � LO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Cycling of plant reduces overall cost per Dth 2025 Natural Gas IRP Appendix ■ 693
�/��ui
25 **No volumes will be available until 2028 1n.5m ®

Liquified Natural Gas ( LNG) Peak Storage
• CapEX - $200MM (50 Year Asset Life — $70 Available in CROME
Avista Rev. Req) ■ Fixed Cost Variable Cost*
• Plant Size — 1 Bcf $60
• Max volume per day 103 700Dth
p Y — � � $50
• Pipeline - $2MM
0
Q $40
• Utility Interconnect - $3. 12MM
• Installation + Owners costs — 30% of capital $30
• Liquefaction Costs Z $20
• Days of peak supply — 10 $10
• Liquefier capacity per day — 7,000 Dth
$Siting, permitting and build - 4 years
• W I,- W M CDr N M � 0 W I- W M CDA N M � 0
N N N N M M M M M M M M M M � � � � � �
CDO CD CD CD O CD CD CD CD CD CD CD CDO O O O O O
• Gas commodity costs included in CROME N N N N N N N N N N N N N N N N N N N N
and combined with estimated nominal $ per *Example only as costs are modeled directly in CROME
Dth
*Cycling of plant reduces overall cost per Dth 2025 Natural Gas IRP Appendix � 694
26 **No volumes will be available until 2030 e��uiVISTA

Constraints of Resource options in CROME
Resource •e F'--Eu- Volurnetric Restrictionof Availability
Allowances 10% of Market per program rules (CCA) 2026
Community Climate Investments 15% (2025-2027), 20% 2028+ (CPP) 2026
Demand Response CPA from AEG for potential 2026
Electrification No constraints, up to total energy demanded on 2026
LDC by area/class/year
Energy Efficiency CPA from AEG and ETO 2026
Renewable Thermal Credit NW Technical Potential (ICF) —Avista Share (16%) 2026
Propane Storage 30,000 Dth 2028
Hydrogen NW Technical Potential (ICF) & Avista Share (16%) 2030
& 20% by volume
Synthetic Methane NW Technical Potential (ICF) & Avista Share (16%) 2030
Renewable Natural Gas NW Technical Potential (ICF) & Avista Share (16%) 2030
Liquified Natural Gas 1 Bcf Total & 0.1 Bcf Daily W/D 2030
Carbon Capture, Utilization and Storage 2030
ConstrairdS5tOAWAtW t iXvolume customers (ICF) 695
27 A', TA®

AEG
APPLIED ENERGY GROUP
Avista Energy
Natural Gas CPA Draft
Results
Prepared for Avista Energy TAC Meeting 1 /9/2025
Confidentiality—The information contained in this presentation is proprietary and confidential. Ilse of thhis informatics.is limited to the intended recipient and its employees and may not be disclosed to third parties.

0
Overview
C Introduction
0 Methodology Overview
C' WA & I D Conservation Potential Assessment
Energy Efficiency
Demand Response
G Oregon Low-Income Energy Efficiency Potential Study
C OR-WA Transport Customer Energy Efficiency Potential
Study
Applied Energy Group, Inc. I apW24UMgWAq P'9a9dix 2 697

Juv
` Assess a broad set of technologies to
identify long-term energy efficient and
y g gy y ,
demand response potential in Avista s '
Washington and Idaho service territories
to support:
CPAIntegrated Resource Planning 'tl�
r
Portfolio target-settingObjectives
Program development / � Ilk
Provide information on costs and p
seasonal impacts of conservation to
compare to supply-side alternatives
Use methodology consistent with the
Northwest Power and Conservation
Council, while recognizing differences
between electricity and natural gas.
Understand differences in energy
consumption and energy efficiency
opportunities by sector, and for
Residential, by income level
Ensure transparency into methods,
assumptions, and results `
Applied Energy Group, Inc. I apkq%MgWAq P'9a9dix 3 698

Methodology Overview
for Washington & Idaho
CPA
4

BaseLine PotentiaL
. - Projection M 6 Estimation
AEG
• Baseline studies • EE equipment • Utility forecasts • Technical
• Utility data • EE measures • Standards and •Achievable Tech.
ModeLing
•Secondary data • Emergingtech. buildingcodes • EconomicAchiev.
-J
Approach
Residential Gas Usage by End Use Natural Gas Projection by End Use
Water Appliances
3%
Heating 140 Cumulative Natural Gas Savings
12%1\ Misce1lneous _ 120 H 4,500 o
■ U) 100 R 4,000
E A
Secondary�� so o 3,500
~ 3,000
2% 2-
Space 40 s 2,500
Heating E 60
Heating
20 2,000
-
0
N N N co co M M 1,000 - -
O O O O O O O
N N N N N N N 500
■�_ ■r_ ■
2026 2027 2030 2035 2045
Applied Energy Group, Inc. apW24UMfi96A6gRPi dix 7005

gInputsMaJ' or Modelin and Sources 00
Avista foundational data Survey data showing Technical data on end- State and Federal Market trends and
presence of equipment use equipment costs energy codes and effects
and energy standards
consumption
Avista gas sales by schedule Avista: Residential customer Regional Technical Forum Washington State Energy Code RTF market baseline data
Current and forecasted survey conducted in 2013 workbooks Idaho Energy Code Annual Energy Outlook
customer counts NEEA: Residential and Northwest Power and Federal energy standards by purchase trends(in base year)
Commercial Building Stock Conservation Council's 2021 equipment class
Retail price forecasts by class Assessments(RBSA 2016 and Power Plan workbooks
CBSA 2019) US Department of Energy and
US Energy Information ENERGY STAR technical data
Administration: Residential, sheets
Commercial, and Energy Information
Manufacturing Energy Administration's Annual Energy
Consumption Surveys(RECS Outlook/National Energy
2020, CBECS 2018, and MECS Modeling System data files
2015)
Applied Energy Group,Inc. I appliedenergygroup.com 6
2025 Natural Gas IRP Appendix 701

v
The first step in the CPA process is to define energy-consumption characteristics in the
1^r/ base year of the study (2021 ).
AEG incorporates Avista's actual consumption and customer counts to develop
"Control Totals"—values to which the model will be calibrated.
Market Market characterization is an important step in the CPA process as it grounds the
analysis in Avista's data and provides us with enough details to project assumptions
Characterizationforward, developing a baseline energy projection.
After separating gas consumption into sectors and segments, it is allocated to specific
end uses and technologies in the Market Profile (next slide).
Natural Gas Use by Sector I
Single Family, Multi-Family, Manufactured
Residential 237,935 16,973,954 Home, and by Income Group within housing
type
Commercial Office, Retail, Restaurant, Grocery, College,
Commercial 24,454 9,814,874
School, Hospital, Lodging, Warehouse, Other
Residential
Mix of industries from customer data will
Industrial 194 496,972 inform presence of end uses and measure
applicability
Total 262,584 27,285,801
Applied Energy Group, Inc. apW24UMgWAqN P)dndix 7027

Example - Washington Residential Washington Residential Natural Gas
Calibrated to Avista's use-per-customer at the LI-Multi- LI Mobile
household level Family Home
1^r/ 5°,° 1 2°,0
e Breaks down energy consumption to the end use
LI-Single
and technology level Family
Energy Defines the saturation (presence of equipment) 22%
and the annual consumption of a given technology
Ma rket where it is present (Unit Energy Consumption — MobileHome��
3%
U Multi-Family EC) Single Family
Proffle
64%
Data taken from NEEA's RBSA/ CBSA surveys, US DOE 4%
Annual Energy Outlook, and Avista's 2013 GenPop
Survey
Single Family Profile WA Residential Intensity(therms/HH)
IrvUEC Intensity Usage 1000
800
Space Heating Furnace 85% 646 548 8,648,686 goo ■Space Heating
Boiler 2% 432 10 160,215 600 ■Secondary Heating
Secondary Heating Fireplace 5% 110 6 88,017 500 ■Water Heating
400
Water Heating Water Heater(<=55 Gal) 55% 145 80 1,258,802 300 . ■Appliances
Water Heater(>55 Gal) 0% 52 0 162 200 ■Miscellaneous
Appliances Clothes Dryer 28% 22 6 97,826 100
Stove/Oven 59% 28 17 260,523
Miscellaneous Pool Heater 1% 106 1 15,120
Miscellaneous 100% 1 1 14,482 ��-
Applied Energy Group, Inc. a4244,�MM NP-*9dix 703

Ju` We estimate three levels of potential.
1^r� These are standard practice for CPAs
in the Northwest:
Estimating Technical: everyone chooses the most
efficient option when equipment fails
E n e rgy regardless of cost. Technical
Achievable Technical is a subset of
Efficiency technical that accounts for achievable AchievabLe
PotentiaL
participation within utility programs as well
as non-utility mechanisms, such as regional
initiatives and market transformation.
Achievable Economic is a subset of UCT and
achievable technical potential that includes TRC
only cost-effective measures. Tests
considered within this study were the UCT Economic
for Idaho and TRC for Washington. Achievable
Applied Energy Group, Inc. I a424UMgWAq P'Randix 7049

For this study, AEG adapted the 2021 Power Plan ramp rates for use in
1^r� a natural gas CPA.
Measure �^ All measures "ramp up" over time to a maximum of 85% adoption
In the 2021 plan, some electric measures have had their maximum
Ramp achievability increased beyond 85%. None of those specific measures apply
EM to natural gas, and AEG has not increased the achievability for any measures
Rates in this study.
Power Council's ramp rates include potential realized from outside of utility
DSM programs, including regional initiatives and market transformation.
A cost-effectiveness screen is applied to equipment measures to address
very high-cost measures before ramp rates are applied, consistent with
Council methodology.
'A AEG considered Avista's recent program achievement when assigning
ramp rates to reflect differences between electric and natural gas
markets.
Applied Energy Group, Inc. I apW24UMgWAq P'9a9dix 705

M- alik
Draft Potential
Results (ALL Sectors)
WON
�.-
7'
4
r

0 Cumulative Achievable Technical Potential reaches 7,280,599
Dth or 27.1 % of the reference baseline b the end of the 20- ear
y y
study period
Summary Cumulative Achievable Economic Potential reaches 2,273,359
ResuLts Dth, or 8.5% of the baseline over the study period
WA(All Sectors,ID
35,000,000 Annual Incremental Potential
Combined) 30,000,000 900,000
800,000
25,000,000 ` 700,000
`� • nn 600,000
S�
20,000,000 >
Q m 500,000
s �
p m 400,000
15,000,000
o 300,000
U
10,000,000 Baseline Forecast c 200,000
Potential-Achievable Economic 100,000
5,000,000 Achievable Technical Potential
I I I' IF I I I I I I I I I I I 11' ■,
�,I
CO I� M M O N M V � (O n W O O N M V t.()
Technical Potential N N N N CO M CO CO CO CO CO M M M V V V V V V
0 0 0 O O o O o 0 O 0 0 0 0 0 0 O 0 0 O
N N N N N N N N N N N N N N N N N N N N
0
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 ■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Applied Energy Group, Inc. I aPWAMM ONP-Rani dix 707

35.0%
■Achievable Economic Potential
30.0%
Achievable Technical Potential
25.0% ■Technical Potential
20.0%
m
0 15.0%
Summary
10.0%
ResuLts
5.0% 110
Continued 0.0%
2026 2027 2030 2035 2045
Summary of Energy Savings(Dth), 2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 30,694,608 30,821,229 30,189,317 28,865,919 26,858,182
................................................... ........
Cumulative Savings(Dth)
......... .. .. .. .. . ......... ......... ......... ......... ......... ......... ......... . . . . . ......... ...... . . . . . . . . . . . . . . . . . ......... ......... .......... . . . . . . . . .
Achievable Economic 101,956 224,167 618,329 1,452,725 2,273,359
......................................... _ __ _ __ _ _ _ _ ...................................... _ _ _ _ _ _ _ _ ......... _ _ _ .................
Achievable Technical 345,378 781,698 2,223,030 5,169,004 7,280,599
............ ...... ......... ......... ......... _ _ .. ..... _ _ _ _ _ _ _ _..... _ _ _ _ .........
Technical Potential 587,137 1,236,115 3,038,374 6,504,292 8,570,562
_._._. _._._. .. ................. .... _ _ _ _ _ _ _ _ _ _ _ _ . . . . . . . _. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ _ _ _ . . . . . . . . . .
Energy Savings(%of Baseline)
................................................................-
Achievable Economic 0.3% 0.7% 2.0% 5.0% 8.5%
Achievable Technical 1.1% 2.5% 7.4% 17.9% 27.1%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... _ _....... . _ _ _ _ __ ........ _ _............... __ ......... _ _ ......... ........____ ....
Technical Potential 1.9% 4.0% 10.1% 22.5% 31.9%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ... .......... . . . . . . . . . .. ......... ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
. . . . . . . . . . . . . . . . . . . . .. .................
Achievable Economic 101,954 121,649 155,584 175,424 56,357
..................... _............... __ _ _ _ ..._ _ _ _ _ _ ...................................
Achievable Technical 345,371 437,413 581,629 625,774 131,572
................................................................................................... .............................................................................................................................................................
Technical Potential 587,129 650,476 730,576 721,826 100,708
Applied Energy Group, Inc. I ap*.44,�MgWap N p.gl$r ,dix 708

Draft Residential
Potential Results
7'
14
lop�-`

Cumulative Achievable Technical Potential reaches 5,299,926 Dth, or
30.8% of the reference baseline by the end of the 20-year study period
ResidentialCumulative Achievable Economic Potential reaches 1 ,010,061 Dth, or
Summary 5.9% of baseline over the study period
Results
(WA & ID 25,000,000
Annual Incremental Potential
Combined) 700,000
20,000,000
600,000
�. 500,000
15,000,000
g ` m 400,000 —
� t
� CO 300,000
10,000,000 aD
U aEi 200,000
Baseline Forecast
5,000,000 Achievable Economic Potential 100,000 , ' ' ' I I I I I I I ' ' ' 1 ■ I�■ 1�. 1
Achievable Technical Potential 0 (0 r, CO 0) 0 N M V LO M r� M W 0 N M V LO
N N N N M M M M M M M M M CO V V V V V V
Technical Potential 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
0
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Applied Energy Group, Inc. I apW24UMcWWAq P-*9dix 710

40.0%
■Achievable Economic Potential
35.0%
J�/�,. Achievable Technical Potential
30.0% ■Technical Potential
1i�r� Q) 25.0%
a)
m 20.0%
0
Summary 0 15.0%
ResuLts
10.0%
Continued 0.0%
2026 2027 2030 2035 2045
Summary of Energy Savings(Dth), 2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 18,987,239 19,099,846 18,823,213 18,249,556 17,185,408
................................................... ........ ............................ _ _ _ _ _ ............................................... __ __ _ _ _ _ ....................................
Cumulative Savings(Dth)
......... .. .. .. .. . ......... ......... ......... ......... ......... ......... ........... . . . . . ......... ..... .. .. . .. .. .. .. ..... .. .. ....... . . . . . . . . . . ... ......... ......................
Achievable Economic 36,948 87,781 242,714 657,590 1,010,061
. ............................ _ __ _ _ _ _ _ _ ................ _ _ _ _ _ _ _ _ _ ........ _ _ _ _ _ _ .........
Achievable Technical 248,509 578,806 1,656,795 3,928,342 5,299,926
............ ...... ......... ......... ......... _ _ . ........- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ........ -
Technical Potential 409,851 872,234 2,083,457 4,625,799 5,945,955
_._._. _._._. .. ................. .... _ _ _ _ _ _ _ _ _ _ _ _ . . . . . _ _ _ _ . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ . . . . . . . . . . . . .
Energy Savings(%of Baseline)
................................................................-
Achievable Economic 0.2% 0.5% 1.3% 3.6% 5.9%
_._._. _._..... . . . . . . . . . _ _._.. _._.. _._._ _._._ _._._ _....... _...... .. . .. .. .. .. _ ...._.. _._.. _..... . . . . . . . . . _ .._..1.1 . . . . . . . . _.....
Achievable Technical 1.3% 3.0% 8.8% 21.5% 30.8%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... _ _.................. _ ___ ........ _ _............... __ ......... _ _ ................_ _ _ _ _I I....
Technical Potential 2.2% 4.6% 11.1% 25.3% 34.6%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. _ .. .. .. .._ ..... ......... ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
.........................................................................................................................................................................................................................................................................................................
Achievable Economic 36,948 50,917 68,500 87,033 19,293
..................... .................... _ _ _ _ _ __ ................................... _ _ _
Achievable Technical 248,509 331,903 446,884 476,864 74,182
................................... ..... .. . .. ............................................................................. . . .....
Technical Potential 409,851 464,676 519,371 534,862 34,879
Applied Energy Group, Inc. ap*.44,�MgWap N p.gl$r ,dix 711

Residential Top Measures (AchievabLe Economic)
_r 0• 0,
IdahoRank EconomicEconomic
EconomicPotential h& . .
Potential(Dth) Potential(Dth)
1 Connected Thermostat-ENERGY STAR(1.0) 71,555 22.6% 1 Furnace 252,172 36.3%
2 Insulation -Ceiling Installation 69,252 21.9% 2 Insulation -Ceiling Installation 85,451 12.3%
L3 Furnace 44,423 14.1% 3 Home Energy Management System(HEMS) 57,291 8.3%
4 ENERGY STAR Home Design 29,219 9.2% 4 Ducting-Repair and Sealing-Aerosol 57,284 8.3%
5 Clothes Washer-CEE Tier 2 16,871 5.3% 5 Water Heater(<=55 Gal) 49,898 7.2%
6 Home Energy Reports 16,867 5.3% 6 Water Heater-Drainwater Heat Recovery 41,161 5.9%
7 Water Heater-Faucet Aerators 15,641 5.0% 7 Clothes Washer-CEE Tier 2 25,511 3.7%
8 Water Heater-Low-Flow Showerheads 14,319 4.5% 8 Home Energy Reports 25,435 3.7%
Building Shell-Air Sealing(Infiltration o Building Shell-Air Sealing(Infiltration
9 Control) 9'099 2.9/0 9 Control) 20,339 2.9%
10 Windows-Low-e Storm Addition 6,015 1.9% 10 Fireplace 11,915 1.7%
Subtotal 293,261 92.8% Subtotal 626,457 90.3%
Total Savings in Year 315,968 100.0% Total Savings in Year 694,094 100.0%
Applied Energy Group, Inc. I appliedenergygroup.com 17
2025 Natural Gas IRP Appendix 712

Residential, Potential. by Income Group
Low-Income potential is proportional to the low-income share of natural gas consumption
Residential Gas Consumption by Segment 20-Year Cumulative Achievable Econonomic
LI-Multi-Family LI-Mobile Home Potential by Income Group
4% � �2%
Low Income Ilk
LI-Single Family
18%
Mobile Home J�tljl 1Z
4%
Multi-Family Single Family Regular Income
5% 67/o 0 67%
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 713

Draft Commercial
Potential Results
7'
19

0 0 Cumulative Achievable Technical Potential reaches 1 ,931 ,836 Dth, or
Commercial21 % of the reference baseline over the 20-year study period.
Summary � Cumulative Achievable Economic Potential reaches 1 ,217,146 Dth, or
13.2% of the baseline.
Results
(WA & . 12,000,000 Annual Incremental Potential
250,000 -
Combined)
. - , 10,000,000
♦♦♦` � 200,000
8,000,000
to
o 150,000 -
- m
6,000,000
m
100,000
a)
11
U 4,000,000
Baseline Forecast 50,000
AchievabLe Economic �2,000,000 Achievable Technical Potentialt fl 0
CO r, CO O O N M V In CD r, CO O O N M V In
Technical Potential 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
0
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 ■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Applied Energy Group, Inc. I apW24UMcWWAq N P'*Rdix 715

30.0%
■Achievable Economic Potential
25.0% Achievable Technical Potential
■Technical Potential
20.0%
erciaL
m 15.0%
Comm
Summary
10.0%
. 5.0% -
esuLts
0.0% �I ■I ■
Continued 2026 2027 2030 2035 2045
Summary of Energy Savings(Dth), 2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 11,229,877 11,244,262 10,890,299 10,142,703 9,203,073
.........................................................................................................................................................................................................................................................................................................
Cumulative Savings(Dth)
.........................................................................................................................................................................................................................................................................................................
Achievable Economic 62,957 132,246 364,283 768,870 1,217,146
. ............................ _ __ _ _ _ _ _ _ .............. ..____ ................ ___ ......... ......... _ _ ..................
Achievable Technical 94,431 197,967 553,157 1,212,068 1,931,836
............ ...... ......... ............... __ _ _ _ . . . .._....... -
_ _ _ _ . .....
Technical Potential 174,326 357,927 939,269 1,844,706 2,567,719
_. _._._. _._._. .. ................. .... _ _ _ _ _ _ _ _ _ . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . . . . . .
Energy Savings(%of Baseline)
................
Achievable Economic 0.6% 1.2% 3.3% 7.6% 13.2%
Achievable Technical 0.8% 1.8% 5.1% 12.0% 21.0%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ..........._ _ ....................... _ _ ......... _ _ ......... ........____ ....
Technical Potential 1.6% 3.2% 8.6% 18.2% 27.9%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. .......... . . . . . . . . . .. ......... ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
.........................................................................................................................................................................................................................................................................................................
Achievable Economic 62,955 68,637 84,298 85,399 35,432
............ __ _ _ _ _ ................................................ _ _ _ _ _ ............................
Achievable Technical 94,424 103,018 131,847 145,822 55,739
.................................................. . . . . . ...........................................
Technical Potential 174,318 182,798 207,770 183,362 63,935
Applied Energy Group, Inc. I ap*.44,�MgWap N p.gl$r ,dix 716

Commercial Top Measures (Achievable Economic ) C)�45 Jr 2045
IdahoRank EconomicEconomic
EconomicPotential Economic
Potential(Dth) Potential(Dth)
1 Furnace 55,089 16.1% 1 Furnace 145,463 16.6%
2 Fryer 37,786 11.0% 2 Destratification Fans (HVLS) 76,738 8.8%
3 HVAC-Energy Recovery Ventilator 30,097 8.8% 3 Ventilation - Demand Controlled 69,390 7.9%
4 Water Heater 26,886 7.8% 4 HVAC-Energy Recovery Ventilator 64,414 7.4%
5 Retrocommissioning 18,855 5.5% 5 Strategic Energy Management 44,680 5.1%
6 Unit Heater 18,435 5.4% 6 Water Heater 44,216 5.1%
7 Water Heater-Pipe Insulation 16,126 4.7% 7 Retrocommissioning 44,020 5.0%
8 Boiler 14,536 4.2% 8 Water Heater- Pipe Insulation 33,466 3.8%
9 Broiler 12,322 3.6% 9 Broiler 28,854 3.3%
10 Oven 10,766 3.1% 10 Griddle 25,480 2.9%
Subtotal 240,898 70.3% Subtotal 576,719 65.9%
Total Savings in Year 342,501 100.0% Total Savings in Year 874,645 100.0%
Applied Energy Group, Inc. I appliedenergygroup.com 22
2025 Natural Gas IRP Appendix 717

Draft Industrial
Potential Results
7'
23

0 �_-, Cumulative Achievable Technical Potential reaches 48,837 Dth, or 10.4% of the
IndustriaL reference baseline over the 20-year study period.
Cumulative Achievable Economic Potential reaches 46,151 Dth, or 9.8% of the
Summary baseline.
Resufts
500,000 Annual Incremental Potential
(WA & . 4,500 —
480,000
4,000 —
t
Combined) 0 3,500
460,000 ao 3,000 — —
° m 2,500
E Q 440,000 i6 2,000
m —• c
o Baseline Forecast 1,500
U
420,000 Achievable Economic Potential 1,000
Achievable Technical Potential — 500
400,000 - —Technical Potential 0
N N III WN 11 O O N 01 V Ln CO CO CO CO O N M V Ln
N N N N (`') C') (`') (`') (`') (`') CO 0 CD CO
CD V V V V V V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
380,000
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 ■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Applied Energy Group, Inc. I apW24UMcWWAq P-*Rdix 719

14.0%
■Achievable Economic Potential
12.0%
0 Achievable Technical Potential
■Technical Potential
cc
8.0%
Industrialcc
00
0 6.0%
Summary 0
4.0%
Results 2.0%
0.0% l I
Continued 2026 2027 2030 2035 2045
Summary of Energy Savings(Dth), 2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 477,492 477,120 475,805 473,660 469,702
................................................... ........ __ _ __ _ __ _ _ __ _ __ _ _ _ _ ...
Cumulative Savings(Dth)
......... .. .. .. .. . ......... ......... ......... ......... . .. .. .. .. . .. .. .. .. . .. .. .. .. .. .. . . . . .. .. .. .. . ......... . ....................... . . . . . . . . . . . . .. .. . . . . . . . . . . . . ..
Achievable Economic 2,050 4,141 11,332 26,264 46,151
........................................... ._._._._ _ _ _ _ _ _ _ _ __ _ _ ............. . _ _11........................-
Achievable Technical 2,439 4,924 13,078 28,594 48,837
. . . . . . . . . . __ _ _ . . . . . _...... _ _ .................
Technical Potential 2,960 5,953 15,648 33,786 56,888
_. _._._. _._._. _._.. ................ . .. _ _ _ _ _ _ _ _ _ _ _ _ _ . . . . . . . . . . _ _ _ . . . _ _ _ _ _ _ _ _ . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy Savings(%of Baseline)
................................................................-
Achievable Economic 0.4% 0.9% 2.4% 5.5% 9.8%
_._._. _._..... . . . . . . . . . _ _._.. _._.. _._._ _._._ _._._ _ . . . . . . . . . . _ .._.. _ . . . . . . . . .......
Achievable Technical 0.5% 1.0% 2.7% 6.0% 10.4%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ... ......... _ _........... .. .. .. .. __ ........ ......... _ _ .................__ ................_ _ _ _ _I I....
Technical Potential 0.6% 1.2% 3.3% 7.1% 12.1%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... .. .. .. .. . .. .. .. .. ___ ........ ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
. . . . . . . . . . . . . . . . . . . . .. ..... .... .. . .. ......... ......... ......... ......... ......... ....... . . . ........ ......... ......... ......... ......... ......... ......... .........
Achievable Economic 2,050 2,096 2,786 2,992 1,633
............ __ _ _ _ _ ....................................................... _ _ _ _ _ _ _ _ _ _ _ _ ...................................
Achievable Technical 2,439 2,492 2,899 3,087 1,650
.........................................................................................................................................................................................................................................................................................................
Technical Potential 2,960 3,002 3,435 3,601 1,894
Applied Energy Group, Inc. I apW24UMgWAq P-*9dix 720

Industrial Top Measures (AchievabLe Economic)
2045 2045
IdahoRank EconomicEconomic
EconomicPotential Economic
1 Process- Heat Recovery 5,697 41.8% 1 Process- Heat Recovery 15,072 46.3%
2 Process Boiler-Steam Trap Replacement 1,816 13.3% 2 Process Boiler-Steam Trap Replacement 3,931 12.1%
3 Process Boiler-Burner Control 1,347 9.9% Process Boiler-Burner Control o
Optimization 3 2,896 8.9/0
Optimization
4 Strategic Energy Management 1,012 7.4% 4 Strategic Energy Management 2,145 6.6%
5 Retrocommissioning 915 6.7% 5 Retrocommissioning 1,942 6.0%
Process Boiler-Insulate Steam o Process Boiler-Insulate Steam
6 Lines/Condensate Tank 601 4.4/0 6 Lines/Condensate Tank 1,289 4.0%
7 Process- Insulate Heated Process Fluids 497 3.7% 7 Process- Insulate Heated Process Fluids 1,078 3.3%
8 Unit Heater 417 3.1% 8 Process Furnace-Tube Inserts 924 2.8%
9 Destratification Fans(HVLS) 400 2.9% 9 Destratification Fans(HVLS) 749 2.3%
10 Process Boiler-High Turndown Burner 272 2.0% 10 Process Boiler-High Turndown Burner 585 1.8%
Subtotal 12,974 95.3% Subtotal 30,611 94.1%
Total Savings in Year 13,615 100.0% Total Savings in Year 32,536 100.0%
Applied Energy Group, Inc. I appliedenergygroup.com 26
2025 Natural Gas IRP Appendix 721

Natural Gas
Demand Response

Approach to the Study
0 0 0 •
- --I
Data • Characterize Develop list of DR Characterize Estimate
• Collection the Market Options the Options Potential
Align with EE Segmentation by Program Options Develop Program Achievable Potential
Potential Study Customer Class • Behavioral Assumptions • Integrated program
• Market • Residential • DLC Smart Thermostats — BYOT • Impacts options without
Profiles • Commercial • Third Party Contracts • Participation participant overlap
Secondary • Industrial • End Use
Sources
Saturations
• DR Program • Costs
Evaluation
Reports from • Incentives
other Utilities
2025 Natural Gas IRP Appendix 723

Changes from Previous Study
The following updates were made to the previous study
Removed all dynamic rate options (TOU, VPP)
Level of sophistication required makes these programs difficult to implement for Gas DR
Removed Water Heating DLC
Costly to implement, unlikely to have high participation, low peak impacts
G Limited Smart Thermostat Program to WA only due to AMI availability
0 Updated per-customer peak therms - lower compared to previous study
0 Updated program assumptions
0 Behavioral Program limited to res-only due to vendor limitations
Applied Energy Group, Inc. I appliedenergygroup.com 29
2025 Natural Gas IRP Appendix 724

Assumptions
Study Assumptions
The programs in this study target the peak hour of the peak day (therms)
Winter only
Program Impact and Cost Assumptions
Derived Primarily from other Gas DR Programs
Smart Thermostat Program based on ConEd Program
Third Party Contracts Program based on National Grid Program
Diverged where gaps in research
Customized for Avista's service territory
Pulled remaining assumptions from Electric DR Study and scaled-down where appropriate
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 725

Advanced Metering Infrastructure (AMI )
Assumptions
Some DR Programs Require AMI
Dynamic Rate and Smart Thermostat Programs require AMI for billing
Washington
Used current Avista AMI saturation rates by sector and held constant
Idaho and Oregon
� No AMI Projected
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 726

AchievabLe o en is
32
2025 Natural Gas IRP Appendix 727

Achievable Potential Forecast (ALL States )
20,000 19,660
N 19,500
19,000 19,505
18,367
18,500
0
18,000 18,340
17,500
_9 '� ,LOB'' ,LOl 'e
—Baseline Forecast Potential Forecast
TotalPotential 1 • 2027 2030 2035 2045
Baseline Forecast (Dth) 18,367 18,428 18,623 18,946 19,660
Market Potential 26 56 147 150 155
Peak Reduction % of Baseline 0.1% 0.3% 0.8% 0.8% 0.8%
Potential Forecast 18,340 18,372 18,476 18,795 19,505
Applied Energy Group, Inc. I appliedenergygroup.com 33
2025 Natural Gas IRP Appendix 728

Washington Potential by Program WA - Winter Potential 2026 2027 2028 2035 M
0
Baseline Forecast(Dth) 9,217 9,207 9,193 9,094 8,956
WA - Winter Potential Achievable Potential (Dth) 22 49 93 125 128
140
Behavioral 7 11 14 13 13
0 120 Third Party Contracts
Ii DLC Smart Thermostats - BYOT 10 29 69 102 105
100
_ ■DLC smart Thermostats- Third Party Contracts 5 8 10 10 10
a° 80 BYOT
60
ro ■Behavioral
40
's
u
a 20
• Only state with Thermostat potential due to AMI
2026 2027 2028 2035 2045 limitations
• Thermostats contribute around 82% of the total
potential by 2045
• Potential across all programs — 1.4% of WA baseline
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 729

Idaho Potential, byProgram
Baseline Forecast(Dth) 5,060 5,115 5,185 5,611 6,288
ID - Winter Potential Achievable Potential (Dth) 3 4 9 14 16
20
z Behavioral - - 4 9 10
0
76 15 Third Party Contracts DLC Smart Thermostats - BYOT - - - - -
0
1 ■DLC Smart Thermostats Third Party Contracts 3 4 6 6 6
CL 10 -BYOT
n
f6 ■Behavioral
°7 5
z
a .
2026 2027 2028 2035 2045 2028 start date for the Behavioral Program for both
ID and OR
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 730

Oregon Potential by Program C)
WinterPotential , . 2027 2028 2035
Baseline Forecast(Dth) 4,090 4,107 4,121 4,240 4,416
OR - Winter Potential Achievable Potential (Dth) 2 3 7 11 11
20
s Behavioral - - 3 6 7
41
a Third Party Contracts _ _ _ _ _
15 DLC Smart Thermostats - BYOT
c ■DLC Smart Thermostats
Third Party Contracts 2 3 4 4 4
a 10 BYOT
d
■Behavioral
01 5
L
U
a
- Lowest potential across all three states due to
2026 2027 2028 2035 2045 limited AMI and proportionally low overall baseline
Dth
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 731

Results by Sector
Potential By Sector
■ Residential
0 200
Commercial
y
a 150 ■ Industrial
0
a
a
m
100
n
a,
L
Q 50
2026 2027 2028 2035 2045
Potential - • 1 • 2027 20281 14
Baseline Forecast(Dth) 18,367 18,428 18,500 18,946 19,660
Achievable Potential (Dth) 26 56 109 150 155
Residential 16 40 89 130 134
Commercial 9 15 19 19 20
Industrial 1 1 1 1 1
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 732

Program Costs
Total Incremental Program Costs Five-Year Levelized Costs ($/Therm-Year)
$1.4
$1.2
Third Party Contracts $443
$1.0
v, $0.8
c
0
$0.6 DLC Smart Thermostats- BYOT $782
$0
$0.2
$0.0 .L r*- 00 rn O . 4 N m �T Ln �O r oo Q, O �1 N m a Behavioral $1,379
N N N N m m m m m m m m m m � Rt Rt It "t It
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
■ Behavioral ■DLC Smart Thermostats- BYOT ■Third Party Contracts $- $400 $800 $1,200 $1,600
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 733

Gas DR KeyFindings qDNatural Gas DR is an emerging resource
Small number of programs in existence
Numerous questions surround the applicability and reliability of Gas DR
Program Potential
Smart Thermostats
Largest savings potential N 82% of potential in WA by 2045
Third Party Contracts
Lowest levelized cost but also lowest potential
o Small amount of customers
o Not a lot of discretionary load to reduce
Applied Energy Group, Inc. I appliedenergygroup.com
2025 Natural Gas IRP Appendix 734

OR Low- Income
Energy Efficiency
Potential Study

Segment Households % of All Homes Usage (Dth) Therms HH
0 1
Single Family 12,289 65.0% 622,559 539
OR Low-Income Multi-Family 4,428 23.4% 88,679 200
Mobile Home 2,197 11.6% 113,191 515
Customers . •
Energy Total 18,914 100.0% 864,429 457
Consumption by
Gas Use by Segment
Home Type
Mobile Home
13%
Multi-Family
10%
Single Family
77%
Applied Energy Group, Inc. I apW24UMgWAq P-*9dix 730

v
For Oregon Low-Income Customers, Cumulative Achievable Technical
Potential is 189,919 Dth or 22.2% of the baseline over 20 years
�^ Cumulative Achievable Economic Potential (TRC) is 51 ,164 Dth, or 6% of
Summary the baseline
(OR Resufts
1,000,000 Annual Incremental Potential
Income)
900,000 30,000
800,000
25,000 —
700,000
to 20,000
0 600,000
•2
cc
E Y 500,000 �n 15,000
:3 p co
c
0 V 400,000 Baseline Forecast 10,000
300,000 Achievable Economic Potential T
5,000
200,000 Achievable Tech ical Potent alTechnicai Potential
100,000 W I, M 0) O N CO V Ln LO r, 00 M O N CO V Ln
N N N N CO M CO M M CO M M M M V V V 'I 'I 'IO CD O CD O CD O O CD O O O O O O CD O
0 N N N N N N N N N N N N N N N N N N N N
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Applied Energy Group, Inc. I apW24UMcWWAq P-*Rdix 73`T

30.0%
■Achievable Economic Potential
25.0% Achievable Technical Potential
■Technical Potential -
1^r� 20.0%
CO15.0%
0
Summary10.0%
ResuLts
5.0% -
Continued 0.0%
2026 2027 2030 2035 2045
Summary of Energy Savings(Dth), 2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 901,274 904,673 896,310 879,805 856,427
........ ............... ......... .........
Cumulative Savings(Dth)
......... .. .. .. .. . ......... ......... ......... ......... ......... ......... ......... ................ ....................
Achievable Economic 2,068 4,856 14,095 39,976 51,164
. .............................................................................. _ _.....................- _ _ _ _ _ ...............
Achievable Technical 9,275 20,777 63,138 155,234 189,919
......................................................._ _.. _............. . _ _ _ _ _ _ _ _....... -
Technical Potential 13,847 29,842 78,653 186,112 221,549
_. _._._. _._._. .. .................. _ _ _ _ _ _ . . . . . . . . . . . . . _ . . . . . . . . . . . . .
Energy Savings(%of Baseline)
..................
Achievable Economic 0.2% 0.5% 1.6% 4.5% 6.0%
_._._. _._..... . . . . . . . . . _ _._.. _._.. _._._ _._._ _._._ _....... ...... .. . .. .. .. .. _ _.. _..... _ .._.. _ . . . . . . . . .......
Achievable Technical 1.0% 2.3% 7.0% 17.6% 22.2%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... _ _........... ............ __ ........ ......... _ _ ......... _ _ ................_ _ _ _ _I I....
Technical Potential 1.5% 3.3% 8.8% 21.2% 25.9%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... .. .. .. .. . .. .. .. .. . __. ........ ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
................................................................................................................................................................. .......................................................................................................
Achievable Economic 2,068 2,789 4,135 5,032 444
_ _ _ _ _ _ ............ __ _ ............................................ _................................................................... .......
Achievable Technical 9,275 11,566 17,115 18,168 1,580
................................................................................................................................................................................. .......................................................................................................
Technical Potential 13,847 16,090 20,697 21,153 1,329
Applied Energy Group, Inc. I ap*.44,�MgWap N p.gl$r ,dix 7A3

^fir
2045 Achievable %of Total
Rank Oregon-Achievable Economic . .
• • Potential (Dth)
Measures 1 Insulation -Ceiling Installation 7,749 15.1%
(OR
• 2 Insulation -Wall Cavity Upgrade 7,107 13.9%
Income) 3 Insulation -Ceiling Upgrade 6,193 12.1
4 Ducting- Repair and Sealing-Aerosol 4,624 9.0%
5 Building Shell-Air Sealing(Infiltration 3,834 7.5%
Control)
6 Furnace 3,297 6.4%
7 Insulation - Floor Upgrade 2,287 4.5%
8 Insulation - Floor Installation 2,254 4.4%
9 Insulation - Ducting 2,073 4.1%
10 Insulation -Wall Sheathing 1,776 3.5%
Subtotal 41,196 80.5%
Total Savings in Year 51,164 100.0%
Applied Energy Group, Inc. apW2q%MM;gkP9a&dix 739

OR-WA Tra n s po rt
Customer Energy
Efficiency Potential
Study

Market Characterization
0 Define energy-consumption characteristics in the base year of the study (2021 ). 4D
C� Incorporates Avista's actual consumption and customer counts to develop "Control Totals" —
values to which the model will be calibrated.
0 Grounds the analysis in Avista data and provides enough detail to project assumptions
forward to develop a baseline energy projection.
0 After separating gas consumption into sectors and segments, it is allocated to specific end
uses and technologies.
Transport Gas Use by State (2021) Transport Gas Use by Segment Transport Gas Use by End Use (2021)
(2021) Miscellaneous
4%
Space
Heating
22%
Oregon
37%
Water
—� Misc Heating
10%
lid
Commercial
3% Industrial 4% Process Food
70% 62% Preparation
2%
dk-� — I
Applied Energy Group, Inc. appliedenergygroup.comApplied Energy Group, Inc. I ap 46
������9����dix 741

Considerations for this AnaLysis iDAvailable potential is largely a function of baseline consumption —
segments with the highest baseline consumption are likely to
have the highest potential
Potential studies rely on average information, which may not
reflect conditions or opportunities for any single customer 0
This is particularly relevant for this study, where a small number of
customers represent a large share of transport load 0
Ramp rates are derived from the Northwest Power and Conservation
Council's 2021 Power Plan and reflect expected adoption across a
broad set of customers. Actual adoption of energy efficiency for large
transport customers may be lumpier based on cycles for implementing
Large capital projects
Applied Energy Group, Inc. I appliedenergygroup.com 47
2025 Natural Gas IRP Appendix 742

Draft
ResuLts
2025 Natural Gas IRP Appendix 743

14,000,000 Annual Incremental Potential
12.000.000 180,000 -
�
10,000 -
10,000,000 p 140,000 to 120,000
0 S
8,000,000
Q CO 100,000 -
Summary - co 80,000
' 6,000,000
UBaseline Forecast 60,000
ResuLts4,000,000 Achievable Economic Potential 40,000
Achievable Technical Potential 20,000 I' I
• 2,000,000 Technical Potential 0 I
(ALL _ _
CO N N O O CV (y) V In O n M O O N -;t V In
N N N N M M M M Cl) CO Cl) M M M V V V V 7 V
O O O O O O O O O O O O O O O O O O O O
0 N N N N N N N N N N N N N N N N N N N N
Transport 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 ■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Sectors) Summary of
2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 12,867,931 12,940,233 12,916,886 12,740,100 12,521,417
........ ............... ......... ......... _ _ _ _ _ ............ .......
Cumulative Savings(Dth)
.........................................................................................................................................................................................................................................................................................................
Achievable Economic 71,410 149,277 405,529 861,783 1,356,513
......................................... _ __ _ _ _ _ _ _ ......................... _ _. __ ................ __ ...................__ . ......... ......... __ _ .
Achievable Technical 112,359 221,738 553,523 1,111,243 1,681,083
. .. .. .. .. .. . . . . _ _ . ...... .._........ _ _ _ . .. .. __ _ _ _ _....... ....... . .
Technical Potential 153,865 302,414 741,338 1,436,433 2,104,270
.........................................................................................................................................................................................................................................................................................................
Energy Savings(%of Baseline)
...............__ _ _ _ _ _ _ _ .... _ _ ...._ _ _ _ _ _ _ ..... __ _ _ _ _ _ _ .............
Achievable Economic 0.6% 1.2% 3.1% 6.8% 10.8%
_._._. _._..... . . . . . . . . . _ _._.. _._.. _._._ _._._ _._._ .._.. . . _ _._. _.. . ..... _._.......... . . . . . . ......... .._- _ . . . . . . . . . . .
Achievable Technical 0.9% 1.7% 4.3% 8.7% 13.4%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. _ _........ ........ _ _................ __ ......... ......... ................_ _ _ _ _I I....
Technical Potential 1.2% 2.3% 5.7% 11.3% 16.8%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. _ .. .. .. .._ .. .. .. .. . _ _ ........ ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
. . . . . . . . . . . . . . . . . . . . .. ..... ......... ......... ......... ......... ......... ......... ....... . . . .. ................................................................................................................
Achievable Economic 71,410 77,638 91,630 89,176 37,661
............ __ _ _ _ _ ............................ _ _ _ .... _ _ _ _ _ _ _ _............................... _ _ _ _ _
Achievable Technical 112,359 109,625 118,608 110,727 44,538
....... .... ..... ....... . . . . . .
Technical Potential 153,865 149,160 155,663 135,624 57,179
Applied Energy Group, Inc. I ap*,44,�MgWgq p.gj$r ,dix 744

OregonAchievable %of
Achievable %
00 Potential Savings• • of
Rank Potential Economic Total • • Total
PotentialEconomic TRC Potential
TransportTop 1 Process- Heat Recovery 241,167 50.3% 1 Process- Heat Recovery 274,917 31.3%
2 Process Boiler- Burner Control 42,084 8.8% 2 Retrocommissioning 70,255 8.0%
Measures Optimization
(ALLStates
3 Retrocommissioning 35,257 7.4% 3 Ventilation- Demand Controlled 53,105 6.1%
4 Strategic Energy Management 32,996 6.9% 4 Process Boiler- Burner Control 47,973 5.5%
Sectors)
Optimization
5 Process Furnace-Tube Inserts 21,174 4.4% 5 Destratification Fans(HVLS) 39,808 4.5%
6 Process- Insulate Heated Process 16,706 3.5% 6 Water Heater 39,619 4.5%
Fluids
7 Destratification Fans(HVLS) 10,447 2.2% 7 Strategic Energy Management 37,637 4.3%
8 Gas Boiler-Steam Trap Replacement 10,434 2.2% 8 Gas Boiler-Steam Trap Replacement 34,553 3.9%
9 Process Boiler- High Turndown Burner 9,253 1.9% 9 Water Heater- Pipe Insulation 26,232 3.0%
10 Process Boiler-Stack Economizer 7,906 1.6% 10 Process Furnace-Tube Inserts 23,907 2.7%
Subtotal 427,423 89.1% Subtotal 648,004 73.9%
Total Savings in Year 479,508 100.0% Total Savings in Year 877,004 100.0%
Applied Energy Group, Inc. I apWA ..WW69RPi dix 745

7 = Thank You .
11f•» �.r.
Andy Hudson, Project Manager
[e-mail]
Fuong Nguyen, Consultant ,14
' [e-mail]
d
.� Tommy Williams, Consultant -'
< [e-mail]
Ken Walter, Senior Manager .L ,a
[e-mail] G
.y
APPLIED ENERGY GROUP

2025 Natural Gas IRP Appendix 747

ConsuffingClient History
Northwest&Mountain: Canada' National: 70
BC Hydro American Society of Mechanical Engineers(ASME)
Avista Energy Hydro One EPRI
Bonneville Power Ad.(BPA) Manitoba Hydro FERC
Black Hills Energy Independent Electric System Institute for Electric Efficiency(IEE)
Cascade Natural Gas Operator(IESO) Lawrence Berkeley National Lab(LBNL)
Chelan PUD
City of Fort Collins US EPA
Colorado Electric*
CowlitzPUD Energy
,
Energy Trust of OR
Eli Morris Idaho Power+-
Inland P&L
Project Director Northwest EE Alliance*
Northwest Power& Northeast&Mid Atlantic:
Conservation Council r
Oregon Trail Electric Co-op AvanGrid(RG&E&NYSEG)
PacifiCorp* Baltimore Gas&Electric
PNGC �" Central Hudson Electric&Gas
Portland General Electric Consolidated Edison of NY
Seattle City Light Delmarva Power
Ken Walter Snohomish PUD Efficiency Maine
National
Analysis Lead Tacoma Power NYSERDA rid
Orange&Rockland
PEPCO
Potomac Energy
PSEG LI/LIPA
Southwest: New Jersey Natural Gas
Alameda Municipal Power NJ BPU
Burbank W&P SMECO
Tommy Williams California Energy Commission State of Maryland
HECO UGI Utilities
Demand LADWP
Response Lead PNMnergy
South:
PG&E Midwest Columbia Gas VA
SCE SDG&E AEP(I&M,Kentucky)* KCP&L Duke Energy
,Q LG&E/KU
SMUD Alliant Energy Minnesota Energy Resources
State of NM Ameren Missouri Midcontinent ISO * Oklahoma Gas&Electric(OK and AR)
State of HI Ameren Illinois* NIPSCO South Mississippi Electric Power Association
And Hudson Black Hills Energy* Omaha Public Power District * Southern Company(Services and utilities) -k
y son Tucson Electric Power
t`.., Project Manager Xcel/SPS Citizens Energy Peoples Gas/North Shore Gas*Spire * TVA
g ComEd State of Michigan
Empire District Electric* Sunflower Electric Power Vectren(IN&OH) currentwork
First Energy* Wisconsin PSC States and Provinces in
Indianapolis P&L which we've worked • AEG offices
As of May 2021
Applied Energy Group I appliedenergygroup.com 2025 Natural Gas IRP Appendix 748

Roseburg - Grants Pass - Medford income Group La Grande
J`'J Above Low Income� Low Income
Under 200%of the Federal Poverty Level
Region
Income by
Klamath Falls
Source:Census American Community Survey 2019,provides accurate estimates of household median income,household
size,and structure type within each block group,
Applied Energy Group, Inc. apWitWW69NP91�1t dix 749

Juv
� Income group segmentation provides Avista an understanding of where these customers
are located differences in their consumption, and levels of energy efficiency savings
p gy y g
opportunities.
US Census data provides the basis of household demographics by location
Objectives Detailed surveys like RBSA capture differences in how customers at different income levels
use energy, which affects savings potential and cost-effectiveness:
and Data Household intensity (therms per home)
Building shell
Sources Presence of equipment
Gas Customer Intensity by Income Level- RBSA II Income Groups by Household Size
Avg. Afrom Low Income
Income ClassTherms/H Regular Threshold
M 1 $25,760
Non-Low-Income 180 636 n/a 2 $34,840
Low Income 55 544 -14% 3 $43,920
4 $53,000
5 $62,080
6 $71,160
7 $80,240
8 $89,320
Applied Energy Group, Inc. I apW24UMgWAq P'9a9dix 750

v
0 "How much energy would customers use in the future if Avista stopped running
conservation programs now and in the absence of naturally occurring efficiency.?„
• The baseline projection answers this question
The baseline projection:
BaseLine
• ' • '
Projection • To the extent possible, the same forecast • Expected impact of naturally occurring
drivers used in the official load forecast, efficiency (except market baselines)
particularly customer growth, natural gas • Exception: RTF workbooks have a market
The baseline prices, normal weather, income growth, etc. baseline for lighting, which AEG's models also
projection is an • Trends in appliance saturations, including use.
distinctions for new construction. • Impacts of current and future demand-side
• _ • _ • _ _ • . Efficiency options available for each management programs
use forecast of technology , with share of purchases reflecting • Potential future codes and standards not yet
natural gas codes and standards (current and finalized enacted
consumption at the future standards)
same level of detaiL • Expected impact of appliance standards that
as the market are "on the books"
• Expected impact of building codes, as reflected
prof i Le. in market profiles for new construction
• Market baselines when present in regional
planning assumptions
Applied Energy Group, Inc. I apW24UMgWAq P'*Rdix 7A6

v
Jul In assessing cost-effective, achievable potential within Avista's
territory, AEG considered two perspectives.
Washington - Total Resource Cost Test (TRC): Assesses cost-effectiveness from the
. mic perspective of the utility and its customers. Includes non-energy impacts if they can be
Econquantified and monetized.
Achievable
Idaho - Utility Cost Test (UCT): Assesses cost-effectiveness from a utility or program
administrator's perspective.
ComponentPotential
Avoided Energy Benefit Benefit
"quor
Non-Energy Impacts* Cost/Benefit *NEI Categories
• Quantified and monetized non-energy impacts
Incremental Cost Cost (e.g. water, detergent, wood)
• Projected cost of carbon in Washington
Incentive Cost • Heating calibration credit for secondary fuels (12%
Administrative Cost Cost Cost for space heating, 6% for secondary heating)
• Electric benefits for applicable measures
10% Conservation
Benefit
Credit
Applied Energy Group, Inc. a424UMM MP-Ragdix 747

��` Lost Opportunity Ramp Rates Retrofit Ramp Rates
100% 10%
80,° ,----- 8% , ,/- � �,%
Council 60% / /OV 6%
II i
Methodology: 40% III 4% ,00e %%
II i
• 20% ♦� 2% II
00, i
Examples 1 4 7 10 13 16 19 1 4 7 10 13 16 19
LO12Med — -L05Med --- L03SIow Retrol2Med - -RetroWed --- Retro3SIow
o Describe the % of units assumed to be Describe the % of the total market that is
adopted relative to all units purchased in acquired in each year
that year (based on lifetime/turnover) Add up to 100% over time, but reach that
0 Approach their maximum limit overtime, total at different speeds
but reach that limit at different speeds
Applied Energy Group, Inc. I apW24UMgWAq P'9a9dix 58 753

600,000 Annual Incremental Potential
14,000
500,000 `
7_ � 12,000
CommerciaL
�- 10,000
CO
400,000 �
c �
0
8,000
a ^ U)
w 300,000 '� 6,000
c
SummaryU Baseline Forecast
4,000
200,00o Achievable Economic Potential
Achievable Technical Potential � 2,000
Resufts
100,000 Technical Potential 0
N N N N M M M M M M M M M M V V V V V V
O O O O O O O O O O O O O O O O O O O O
(ALLStates)
N N N N N N N N N N N N N N N N N N N N
0
2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
■Achievable Economic Potential Achievable Technical Potential ■Technical Potential
Summary of
2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 3,583,743 3,585,198 3,509,734 3,367,345 3,210,679
........ ............... ......... .........
Cumulative Savings(Dth)
......... .. .. .. .. . ......... ......... ......... ......... ......... ......... . . .._.... ....... ......... ..... .. . . . . . . . . . . . . . . . . . . . . . . . . .. .... .. .. .. .. . . . . . . . .
Achievable Economic 25,173 55,342 153,330 304,312 422,876
......................................... _ __ _ _ _ _ _ _ ......................... .. _ _ _ _ _ _ _ _ _ _ _ _ ....... ..
Achievable Technical 66,111 127,768 301,119 552,841 744,546
............ ...... ......... ......... ......... _ _ . ................
Technical Potential 95,671 184,390 427,480 753,510 966,787
_._._._._._._._._._._._._._._............................ _ . . . . . . . . . . .....
Energy Savings(%of Baseline)
..................
Achievable Economic 0.7% 1.5% 4.4% 9.0% 13.2%
Achievable Technical 1.8% 3.6% 8.6% 16.4% 23.2%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... ........... .........___ ........ .........
Technical Potential 2.7% 5.1% 12.2% 22.4% 30.1%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. _ .. .. .. .._ ..... ......... ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
.........................................................................................................................................................................................................................................................................................................
Achievable Economic 25,173 30,211 35,233 28,832 7,585
............ __ _ _ _ _ ..................................................................................................................................
Achievable Technical 66,111 62,174 62,132 50,182 14,248
.........................................................................................................................................................................................................................................................................................................
Technical Potential 95,671 89,617 86,107 62,781 20,178
Applied Energy Group, Inc. I ap*,44,�MgWgq p.gj$r ,dix 7A9

Oregon-Achievable Economic TRC Achievable %of Washington-Achievable Achievable %of
Rank Potential Economic Total • • Total
PotentialEconomic TRC Potential
•
Gas Boiler-Steam Trap
1 Replacement 10,419 22.8% 1 Ventilation- Demand Controlled 52,001 13.8%
Commercial 2 Water Heater 5,669 12.4% 2 Water Heater 39,619 10.5%
Transport Top 3 Water Heater- Pipe Insulation 5,443 11.9% 3 Retrocommissioning 35,455 9.4%
Measures 4 Fryer 5,152 11.3% 4 Gas Boiler-Steam Trap Replacement 34,537 9.2%
5 Retrocommissioning 4,886 10.7% 5 Destratification Fans(HVLS) 28,495 7.6%
6 Gas Boiler-Thermostatic Radiator 3,405 7.4% 6 Water Heater- Pipe Insulation 26,232 7.0%
Valves
° 7 Gas Boiler-Thermostatic Radiator 22,070 5.9%
7 Range 3,290 7.2/o Valves
8 Gas Boiler- Hot Water Reset 2,682 5.9% 8 Gas Boiler- Insulate SteamLines/Condensate Tank 17,882 4.7%
9 Steamer 1,387 3.0% 9 Gas Boiler- Hot Water Reset 17,382 4.6%
10 Broiler 880 1.9% 10 Gas Boiler-Stack Economizer 13,625 3.6%
Subtotal 43,213 94.5% Subtotal 287,298 76.2%
Total Savings in Year 45,736 100.0% Total Savings in Year 377,141 100.0%
Applied Energy Group, Inc. I apW24UMM;gkP9a&dix 755

9,600,000 Annual Incremental Potential
9,400,000
JJ�� 0,000
9,200,000 8
0,000
9,000,000 0 70,000
8,800,000 to 60,000
0 -
Q-- 8,600,000 � 50,000 -
d E
a 9 8,400,000 �� +a 40,000
c �
0 8,200,000 Baseline Forecast 30,000
Summary
Achievable Economic Potential 20,000
8,000,000 Achievable Technical Potential 10,000
Results 7,800,000 Technical Potential 0
ID r� W M O N M V W W 1, W M O N M V lD
7,600,000 N N N N CO M CO CO CO CO CO Cl) CO CO V V V V V V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N TechNnicaN(Potential
NNNN N N N N
7,400,000 ■Achievable EconomicPotential Achievable ■Technical Potential
(ALLStates) 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Summary
of
2026 20272030 2035 2045
Selected Years
Reference Baseline(Dth) 9,284,188 9,355,036 9,407,151 9,372,755 9,310,738
........ ............... ......... .........
Cumulative Savings(Dth)
......... .. .. .. .. . ......... ......... ......... ......... ......... ......... . . .._....
Achievable Economic 46,236 93,935 252,199 557,471 933,636
......................................... _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .........
Achievable Technical 46,248 93,970 252,404 558,402 936,537
............ ...... ......... ......... .........
Technical Potential 58,193 118,024 313,857 682,924 1,137,484
_ .. . _._._. _._._. .. ................. .... _ _ _ _ _ _ _ _ _ _ _ _ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy Savings(%of Baseline)
............................................................................. ._
Achievable Economic 0.5% 1.0% 2.7% 5.9% 10.0%
_._._. _._..... . . . . . . . . . _ _._.. _._.. _._._ _._._ _._._ ......... _._._. _.. . . . . . . . . . . . . . . . . . . . . . _ .._..1.1 . . . . . . . . .......
Achievable Technical 0.5% 1.0% 2.7% 6.0% 10.1%
_ .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ... ......... ......... _.........__ ........ ......... _ _ .................__ ................_ _ _ _ _11....
Technical Potential 0.6% 1.3% 3.3% 7.3% 12.2%
. .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. . .. .. .. .. ......... ......... ......... ......... ......... ......... ......... ......... ......... ......... .........
Incremental Savings(Dth)
.........................................................................................................................................................................................................................................................................................................
Achievable Economic 46,236 47,428 56,397 60,344 30,076
.....................
Achievable Technical 46,248 47,451 56,476 60,546 30,290
......................... ................................................................................................
Technical Potential 58,193 59,543 69,556 72,844 37,001
Applied Energy Group, Inc. ap*.44,�MgWgq N p.gl$r ,dix 75%1

2045 2045
• EconomicAchievable
Rank Potential Economic Total Rank
1�rr EconomicEconomic Total
Potential Savings •.
tential Savings
1 Process- Heat Recovery 241,167 55.6% 1 Process- Heat Recovery 274,917 55.0%
IndustrialProcess Boiler- Burner Control Process Boiler- Burner Control
2 Optimization 42,084 9.7% 2 Optimization 47,973 9.6%
Transport
3 Strategic Energy Management 32,996 7.6% 3 Strategic Energy Management 37,637 7.5%
To , 4 Retrocommissioning 30,372 7.0% 4 Retrocommissioning 34,800 7.0%
Measures
5 Process Furnace-Tube Inserts 21,174 4.9% 5 Process Furnace-Tube Inserts 23,907 4.8%
Process- Insulate Heated Process ° 6 Process- Insulate Heated Process 19,029 3.8%
6 Fluids 16,706 3.9/o Fluids
7 Destratification Fans(HVLS) 10,447 2.4% 7 Destratification Fans(HVLS) 11,312 2.3%
8 Process Boiler- High Turndown Burner 9,253 2.1% 8 Process Boiler- High Turndown Burner 10,562 2.1%
9 Process Boiler-Stack Economizer 7,906 1.8% 9 Boiler 10,383 2.1%
10 Process Boiler-Steam Trap 5,882 1.4% 10 Process Boiler-Stack Economizer 8,994 1.8%
Replacement
Subtotal 417,986 96.4% Subtotal 479,513 95.9%
Total Savings in Year 433,773 100.0% Total Savings in Year 499,863 100.0%
Applied Energy Group, Inc. I apW2qC";A%;gkPka�dix 757

popro—
Nor-
'ram,- ♦ j� L� �`.
A /
Energy Efficiency Resource Assessment
Avista 2025 IRP 1 _. Ener Trus+
January 9, 2025 of Oregon

Agenda
• About Energy Trust
• Resource Assessment Model Overview
• Draft Avista 2025 Resource Assessment Results and Deployment
Forecast
4�'

About us

Clean and affordable energy since 2002 j
jj
j
From EnergyTrusts investment of $2.8 billion in utility customer funds: j
Y j
j
j
j
w j
\rJV"
j
825,000 sites 30,000 clean energy $13.5 billion in savings 42.9 million metric tons j
j
transformed into energy systems generating over time on participant if carbon dioxide j
efficient health renewable power from unlit bills from their j
y, p y emissions kept out of j
comfortable and the sun, wind, water, energy-efficiency and our air, equal to removingj
j
productive homes geothermal heat and solar investments 11 .2 million cars from our j
j
and businesses biopower roads for a year j
j
jjj
j
jjj
j
2025 Natural Gas IRP Appendix 761 j
j

Energy Trust Resource Assessment Model Overview

Resource Assessment Model Background j
j
j
Estimate of 20-year energy efficiency potential j
j
"Bottom-up" modeling approach j
j
j
,1 • Measure level inputs are scaled to utility level j
j
j
Measure inputsj
9 Baseline and efficient equipment j
j
�- I . � • Measure savings j
Incremental cost j
• Market data j
j
Utility inputs j
j
• Load and customer count/buildingstock forecast j
j
j
• Customer stock demographics j
• Avoided costs j
j
j j
\�� 2025 Natural Gas IRP Appendix 763 j

ModelingUpdates j
j
j
j
• Measure d u ates j
p j
� . Measure savings, incremental cost j
j
• New measures j
j
Emerging technologies j
:� �> - .3? • 2022 Residential BuildingStock Assessmentj
�- � (NEEA) j
j
• Total measure density, technical suitability and baseline j
j
initial saturation j
j
• Heating fuel , water heating fuel splits j
j
j
] j
� 2025 Natural Gas IRP Appendix 764 j
1

Forecasted Potential Types
Technical Potential
Achievable Potential within Calculated rnmaa
Model
Not
Technically
Feasible Cost-Effective Achievable
Market
Barriers ec Potential
ot
E Cost-
Effective 51 Developed
,e o
Program Design Final Program w
MarketPenetration Savings Pas s
Potential Information
ket
--------------

- Cost-Effectiveness Screen
j
- j
j
j
• RA model utilizes the Total Resource Cost (TRC) j
j
test to screen measures for cost-effectivenessit s
j
jj
j
' Total Measure Costj
j
j
be e s
• Measure n fit
j
,.E � • NPV avoided costs per first-year Therm j
` � • Quantifiable non-energy benefits j
j
j
Measure costs j
j
j
• The customer cost of installing an efficiency measure j
(full cost for retrofits, incremental over baseline cost for j
j
replacements and new construction j
� � j
j
• Cost-Effectiveness Override j
j
j
• Measures unpd er,anPAOPUC exception ,� j
ra j
i

Draft Resource Assessment Results
Avista, 2025 IRP

Draft Cumulative Potential by Sector and Type
16
,a
,z
� a
75
73 6
0
2 1 �
0
Residential Commercial Industrial
• Technical Achievable Cost-Effective Achievable

Draft Cumulative Potential by End Use
s
s
E '
a � 9 9 9
Gooi> PQ c°¢ c ¢l`
Technical Achievable Cost-effective achievable
*Chart includes major end uses only and does not add Up roNYel'palYM�ah„i• 769
S��M/

Draft Results and Deployment
20- ear Ener Efficienc Potential Therms
Epr
ost-EffectiveqrDraft Savings
PrSecltorp Technical Potential AchievablePot chievable Potenti Projection*
Residential 15,204,642 13,442,065 13,179,722 9,012,951
Commercial 6,576,079 5,627,220 5,451 ,669 4,771 ,648
Industrial 659,579 560,642 530,695 792,664*
Total 22,440,299 19,629,927 19,162,086 14,577,215
Previous IRP— Com arson
20231RP Total 27,632,901 22,324,557 21 ,604,916 15,368,375
Change -19% -12% -11% -5%
*Draft Projections include exogenous savings. As such°;5t Yeiuy can excee 70
d the 20-year cost-effective achievable totals

Draft Avista Deployment, Cost-Effective Achievable Potential
1,000,000
M,
900,000
800,000
700,000
600,000
E
500,000
400,000
300,000
200,000
100,000
0
O�� OHO O�" OHO OHO On'O O�'� O�� O�� OA'� O"� OHO O"'� OA'O OA'O OHO O��
� ti � ti � ti � ti ti ti ti � ti � ti � ti
■ Commercial New ■ Commercial Existing ■ Residential New ■ Residential Existing ■ Multifamily Existing ■ Industrial ■ Large-Project Adder
*Chart shows total expected efficiency and includes sgXIgR,s,kRf#ppod�es and standards. Energy Trust may not claim the 171
entirety of savings depicted above '
I

Draft Deployed Savings Compared to Load Forecast
zs%
20% *19%
15%
N ' S
00/ `�ti titi titi titi M1ti O ''^ ,,r" O^'A " Gas
OAS ^"b rye^ �0 ry 9
Annual Share of Load Cumulative Share of Load
$K �CAverage AnnuazrE titl`a'dSaved' 0.95 rrz

Questions?
Thank you !
_ Willa Perlman, Planning Project Manager
[e-mail]
� �_ Energ)Trust

Dual fuel ( Hybrid ) Heat Pump Pilot IL
Avista IRP Meeting ow = "
January 9, 2025 2025 Natural Gas IRP Appendix EnergyTrust^

i \
Agenda
9 Y
What is Dual Fuel HVAC (Hybrid HVAC) �
y \
f
f
{
. :� Research objectives
�
J �
Y 4
High-level description of pilot design
�
N
r9 Demographic focus education and support
pp
9 Home criteria
Pilot delivery, installation quality assurance
i 1
Technical specifications and utility/geographic sco e
t pp
. .. Current Pilotmilestone
s �
r \
�S \
,rt \
Pilot considerations �
•' A I
.� Timing �
Next steps
�
t
. s+ f
�k.
��` 2025 Natural Gas IRP Appendix 775
, 4 g

2025 Natural Gas IRP Appendix 776

Definition of Hybrid (dual fuel ) HVAC
• For this Hybrid HVAC is a dual fuel s stem where a ducted
pilot, y
single-speed heat pump and programmable thermostat are added
to an existing gas furnace .
• The pilot application is in single-family homes without air
conditioning and with gas furnaces that are five years old on
average.
• Homes have been previously weatherized
• Homes do not have deferred maintenance that would prohibit successful
installation or operation of HVAC system
• Homes do not need major duct repair
• Homes do not need major electrical service upgrades such as a new panel
or braker box
2025 Natural Gas IRP Appendix 777

Research
2025 Natural Gas IRP Appendix 778

Research Objective 1
Determine the utility system costs and benefits of
hybrid HVAC system installations.
• Fuel use — gas and electric
• Load/demand — gas and electric
• Carbon intensity — gas, electric and overall
2025 Natural Gas IRP Appendix 779

Research Objective 2
Determine the customer costs and benefits of hybrid
HVAC system installations.
• Energy costs — gas, electric and overall
f • Added coolingvalue
• Comfort and living conditions
• Backup auxiliary-fuel
• Maintenance and upkeep
2025 Natural Gas IRP Appendix 780

i Research Objective 3
Determine the costs and process considerations
i� associated with installing Hybrid HVAC systems in
{�. f, low-income households.
r Other necessary infrastructure changes — electric
panels, ducts, etc.
• Homes served and homes disqualified
• Geographic regions served well and those we had
� difficulty serving — customer base size, installation
contractors, supply chain
- _ Cost of installations — Hybrid HVAC system , other
infrastructure, Energy Trust costs
• Timeline for installations — customer recruitment to
successful implementation and use
2025 Natural Gas IRP Appendix 781

•
2025 Natural Gas IRP Appendix 782

� Pilot Description
• Energy Trust to pay full cost of installs \
. low-income qfied weathenzati n servs , �esly served
by \
• Homes must be weatherized and have a gas
olderfurnace no than
ral AC
• House iage andcustomee isting
eduaton and
t
support provided by Energy Trust staff
• Installation contractors selected through RFQ
projects awarded on a rolling
asis
• Post
home install
QA provided by Energy b Trust in
e

� Heat Pump Specifications and Cost
• Heat pump size determined through Manual J , and cooling
needs of the home (in alignment with ACCA2 Standard)
• Cross-over temperature
• Energy Trust will leverage our installation Contractor RFQ to solicit
� more professional feedback on best practices
• Goals - avoid customers experiencing no-heat conditions when \
heat pump switches to defrost mode \
• Follow manufacturer requirements depending on make/model \
• Stay within technical capabilities of equipment selection and
L controls \
• Thermostat selection also to be explored through RFQ
• Cost range between $ 10,000 - $12,000 (not to exceed
$13,000) per fi°orri,e Appendix 784

Geographic Assumptions
• Prioritize overlapping gas and electric territories
• Concentrate efforts regionally to maximize delivery
resources
• Leverage utility insights to support customer acquisition
MEW M
Pacific Power 20
PGE 20 Gas Electric Quantity Geography
NW Natural 26 NWN PGE 50 Portland Metro
Avista 12 AVI PAC 20 S. Oregon / Klamath
Cascade Natural Gas 12 CNG PAC 20 Central / Eastern
90
2025 Natural Gas IRP Appendix 785

Marketing
Total number of homes included in marketing lists :
2,038 customers
What is the breakdown of these per gas utility?
a AVI - 164 customers
a CNG - 34 customers
o NWN - 1 ,840 prior Energy Trust gFAF participants
What is the breakdown of these per electric utility?
a PGE - 1 ,530 customers
a PAC - 508 customers
*Recruitment tactics include emails, postcards, a letter, follow-up
phone calls, event tabling .
2025 Natural Gas IRP Appendix 786

Installations
Installations Compete
Avista - 2
Ca Natural Gas - 1
NW Natural - 21

Pilot criteria re-design considerations
• Age of existing furnace 9 (cooling )
• Presence of central air conditionin
• Income qualification requirement

Evaluation
Energy Trust recently completed a solicitation to select a contractor for the first
phase of the pilot evaluation.
• This first phase will be focused on the pilot process including successes and
places to grow and shift, customer choices and value associated with the
system, and an added market assessment with trade allies installing these sorts \
of systems outside of the Energy Trust pilot in market-rate environments. This \
work will be conducted by Apex Analytics and Ideal Community Strategies and is
expected to be completed in Q4 2025.
• The second phase of the pilot evaluation is expected to begin in Q1 2026.
Another public solicitation for a contractor will be conducted to select an
evaluation firm to perform an impact analysis, including electric and gas usage, \
carbon accounting, and peak system impacts observed by installed pilot
systems.
2025 Natural Gas IRP Appendix 789

2025 Natural Gas IRP Appendix 790

Level ProjectHigh Timeline
May 2023—August July 2025—
• Implementation Customer =11nns & Pro ect
PJ
P9
tannin recruitment site treatment Evaluation \
• Stakeholder Site Y
eli ibilit Post-install \
eligibility
engagement a ement verification verification & \
• Measure development QA• \
P \
Installer recruitment
E
- - "'°"2025 Natural Gas'f pp" 791

Thank You �
-- -- -_--_ --- Andrew Shepard
Andrew.shepard@energytrust. orgM 11,160 Ook,-�-
- 7
Sew r rJ�.�
Trust \
"',!r i"t►.r. % . r, 2025 Natural Gas IRP Appendix of Orego7Q2 \
44C, _ \

�iivlSTA'
TAC 10 — 2025 Avoista Gas I RP
Edited Alternative Fuel Volumes

Alternat 'ive u e ri ces
2025 Natural Gas IRP Appendix 794
'edIII/onSTaa

Alternative Fuel Prices Inputs
Model Restriction Capital Costs
L L
• Selection for any physical
• Equipment
products will not be available in
p • Pipeline Costs
the model until 2030 • Installation and Owners Costs
• Avera e rices above 75 er O&M Fid and Variable
g p � p
Dth will not be modeled • Electricity rates
• Gas rates
2025 Natural Gas IRP Appendix 795
'eIIII1f STA®

Prices
• Expected prices are broken down between northwest and national
technical potential (ICF)
• All prices consider Inflation Reduction Act (IRA) incentives where applicable
• These prices assume a first mover access to alternative fuels
• Prices are from the Northwest for each alternative fuel and National for Renewable
Thermal Credits (RTC)
• Hydrogen (1-12) & Synthetic Methane (SM) prices will be treated as a purchase gas
agreement where Avista would sign a term contract, each year, with the producer
for these prices through the forecast.
• Renewable Natural Gas (RNG) assumes a proxy ownership with costs levelized
over 20 years
• RTC considers a production cost plus, where prices cover all costs
• These exclude Investment Tax Credit (ITC) or Production Tax Credit (PTC) and consider
a higher capital rate
• Prices are in nominal dollars
2025 Natural Gas IRP Appendix 796
III/VFSTa

Hydrogen ( H2) and Synthetic Methane (SM )
Hydrogen Synthetic Methane
$100.00 $100.00
$ 0.00 Blue Hydrogen 1 Biomass 1
Green H2-Wind+Electrolysis 1 $90.00 Biomass 2
$80.00 GreenH2-Solar+Electrolysis 1 Biomass 3
Microwave Pyrolysis 1 G $80.00
a $70.00 L $70.00 Green H 2-B iogen icCO2 1
d
$60.00 a
$60.00
$50.00
E $40.00 £ $50.00 _
O O $40.00
Z $30.00
Z
$20.00 _r $30.00
$10.00 $20.00
$_ $10.00
Col.- 00 O O � N M 14 LOW 1­ 00 (n O r N M � LO
$-
0 0 0 O O O O O O O O O O O O O O O O O (O � OD M O r N M � LOW I,- 00 O O � N M .1 W
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M Iq 11 111*
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
ICF levelized the Section 45V tax credit over 20 years. Since hydrogen
projects must be under construction by the end of 2032 to qualify for
45V credits, the 45V tax credits were modeled until 2035 as a
conservative estimate assuming every new hydrogen facility beginning
construction after 2032 may not qualify for the tax credit. ICF assumed
EAC requirements and other requirements for 45V credits are met to
minimize the CI which doesn't include embodied emissions and receive
the maximum credit amount of $3/kg.
2025 Natural Gas IRP Appendix 797
�IIIIVISTAW

Renewable Natural Gas (RNG)
RNG - Low $ Feedstock RNG - Higher $ Feedstock
$35.00 RNG -LFG 2 RNG -LFG 3 $100.00 g
s $30.00 RNG -LFG 4 RNG -LFG 5 $90.00
p RNG -WW 3 RNG -WW 4
a $25.00 RNG -WW 5 p $80.00
Q $70.00 i
$20.00 $60.00
$50.00
o $15.00
Z o $40.00
$10.00 Z
$30.00
$20.00
$5.00
$10.00 RNG -AM 4 — RNG -AM 5 —RNG -FW 3
RNG -LFG 1 RNG -WW1 RNG -WW2
CO 1.- CO CA O N M -It to CO 1-- CO O1 O r N M ICT LO CO 1- 00 O) O � N M IRT 0 CO 1.- W O O N M 11 N
N N N N M M M M M M M M M M 0 0 CD CD (D CD N N N N M M M M M M M M M M 0 0 0 CD CD CD
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
*Blend of national and NW estimated costs for RNG fa¢mMi[�sral Gas ARP Appendix 798
s **Includes ITC/PTC until 2030 AMESTA®

Renewable Thermal Certificate (RTC)
RTC - Low $ Feedstock RTC - Higher $ Feedstock
$50.00 $160.00
s $140.00
p $40.00 p
$120.00
Q
$30.00 $100.00
c = $80.00 �_
Z $20.00 Z $60.00
$10.00 RTC (RNG -LFG 2) RTC(RNG-LFG 3) $40.00
RTC (RNG -LFG 4) RTC(RNG-LFG 5) RTC (RNG -AM 4) — RTC (RNG -AM 5)
RTC (RNG -WW 3) RTC(RNG-WW 4) $20.00 RTC (RNG -FW 3) — RTC (RNG -LFG 1)
$- RTC RNG -WW 5 $- RTC (RNG -WW 1) RTC (RNG -WW 2)
to r­ 00 0) O r N M .4 M O ti 00 C> O r N M 't LO CO h 00 0) O r N M qt 07 W I- CO Cn O r N M le 1A
N N N N M M M M M M M M M M I Iq qt qt It N N N N M M M M M M M M M M qt qt It It It le
O O O O O O O O O O O O CDOCDOO O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1-No ITC, considers price from producer to create RTC and cover cos;92t @t4dh"m§` 799
7
2-Not tied to market actual prices ���iVISTA®

Carbon Capture , Utilization and Storage (CCUS)
$50.00
$45.00 under 25 Dth/hr- $1,000
Industrial CCUS $900
$40.00 25-50 Dth/hr- under 25 Dth/hr-
$35.00 Industrial CCUS O $800 Industrial CCUS
U $700 25-50 Dth/hr-
$30.00 50-100 Dth/hr- Industrial CCUS
Industrial CCUS 2 $600 50-100 Dth/hr-
a $25.00ilillillwaso�
100-200 Dth/hr- a) Industrial CCUS
to, 1111111 a $500
� $20.00 Industrial CCUS � 100-200 Dth/hr-
$400 Industrial CCUS
$15.00 200-400 Dth/hr- c
p Industrial CCUS $300 200-400 Dth/hr-
Z $10.00 C Industrial CCUS
$5.00 800-1600 Dth/hr- Z $200 800-1600 Dth/hr-
Industrial CCUS Industrial CCUS
$- Direct Air Capture- $100 Direct Air Capture-
CO 000rno NMleLO (D [­ 000) o NMleLn DAC CCUS DAC CCUS
N N N N Cl) M M M M M M M M M 11 11 NT 11 11 � $"
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (O 1*- 00 0) O N M 1* Ln (O 1-- 00 0) O N M I LO
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M It 11 qe q1 11q4'
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Avista specific high-volume customers 2025 Natural Gas IRP Appendix 800
$ �iIVISTA
**Includes ITC/PTC to 2030

Alternative Fuels Technical Potential Volumes
( ICF)
2025 Natural Gas IRP Appendix 801
�IIIIV�STa

Updated Technical Potential Volumes
• Total Technical Potential Volumes have been updated from the final
version of TAC 9 (12/18/2024)
• These volumes were overestimated based on interpretations of
math provided by ICF
Clarification was given by ICF on January 3rd and Impacted deterministic runs
- The "output Excel files list a unit of 1x10e9 Btu for various resources. This is equivalent to
billion Btu. If one were to enter 1x10E9 into an Excel file, you will get 10 billion
10,000,000,000). However, this is because the number should be interpreted as 1x109. The
`e" is meant to stand for "exponent"whereas entering the sequence 10E9 in Excel is
interpreted as 10 x 10 .
The good news is the final number matched closely to those Avista
adjusted for estimated volumes, so now all volumes for alternative fuels
are from ICF study directly
• These deterministic alternative scenarios will be reviewed along with final
content in TAC 11
The deterministic PRS will be discussed further in TAC 10
2025 Natural Gas IRP Appendix 802
'e,71 h/'lSTa®

Volumes
• Expected volumes are broken down between Northwest and National
technical potential
These volumes assume a first mover access to alternative fuels
• Weighted by US population for states where some form of climate policy is in
place or demand is expected
Modeled physical potential volumes are from Avista's weighted share in the
Northwest and intended to represent all volumes available to Avista in the
United States
RTC are the only National potential volumes considered and assumes physical
pipeline accessibility to meet CCA and CPP program rules
Broken out by 2023 number of meters between LDCs in Oregon and Washington
Company 2023#of Meters Share
AVA 379,223 15.831%
CNG 316,929 13.231%
NWN 799,250 33.366%
PSE 900,000 37.572%
Total NW 2,395,402 100.000%
20 5 Natu al Gas IRPA pe dix 803
11 *Renewable Energy Technical Potential - The renewable energy technical potential o? a technology is its achievable energy generation given _ _
system performance, topographic, environmental, and land-use constraints.
AuiVISTA

Hydrogen - Avista's Share
Technical Potential Volumes (2026=2045)
70
60
50
40 p _
0
30
s
20 _
10
W r` CO 0) O N M IqT LO O r` 00 0) O N M 11 LO
N N N N M M M M M M M M M M IRT q* 1* 1* 11 Iq
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Blue Hydrogen National Blue Hydrogen NW Green H2-Wind+Electrolysis National
Green H2-Wind+Electrolysis NW GreenH2-Solar+Electrolysis National Green H2-Solar+Electrolysis NW
■Microwave Pyrolysis National Microwave Pyrolysis NW Plasma Pyrolysis National
Plasma Pyrolysis NW Thermal Pyrolysis National Thermal Pyrolysis NW
*H2 will be limited by volume to 20% 2025 Natural Gas IRP Appendix ■ 804
�/��ui
12 **No volumes will be available until 2030 In.5m ®

Synthetic Methane - Avista's Share
Technical Potential Volumes (2026=2045)
1,200
1,000
800
N
0 600
a
400
a�
0 200
1 1
c0 ti CO M O N M It 0 cD ti 00 M O N M 0
N N N N M M M M M M M M M M le 11 It 11 V 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
■Biomass National Biomass NW
■Green H2-BiogenicCO2 National GreenH2-BiogenicCO2 NW
GreenH2-CCS National GreenH2-CCS NW
■GreenH2-DAC National ■GreenH2-DAC NW
■PinkH2-National-BiogenicCO2 National ■PinkH2-National-CCS National
■PinkH2-National-DAC National ■PinkH2-NW-BiogenicCO2 NW
■PinkH2-NW-CCS NW PinkH2-NW-DAC NW
2025 Natural Gas IRP Appendix 805
13 *No volumes will be available until 2030 �iIVISTA

Renewable Natural Gas - Avista's Share
Technical Potential Volumes (2026=2045)
70
60
50
N
C
0 40
30
m
t
20
10
O ti CO (n O r N M 11 Ln O ti 00 O O N M Ln
N N N N M M M M M M M M M M I It 1 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG -AM National RNG -AM NW RNG - FW National RNG - FW NW
RNG - LFG National RNG - LFG NW ■RNG -WW National RNG -WW NW
2025 Natural Gas IRP Appendix 806
14 *No volumes will be available until 2030 edu VISTA`

Renewable Thermal Certificate - Avista's Share
Technical Potential Volumes (2026=2045)
45
40
35
30
c
25
20
a
m
0 15
10
5
A
t0 � CO M O r N M � LO CC N. 00 M O r N M I Ln
N N N N M M M M M M M M M M It It Iq 11 11
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG (National) -AM National RNG (National) - FW National
RNG (National) - LFG National RNG (National) -WW National
2025 Natural Gas IRP Appendix 807
15 *Volumes are available to the model in 2026 'ediI Vmsma

CCUS (2026=2045)
2.50
Direct Air Capture-DAC CCUS
2.00 (1 MTCO2e Reduction eq) (blank)
800-1600MMBtu/hr-Industrial
CCUS (1 MTCO2e Reduction eq)
U) (blank)
■200-400MMBtu/hr-Industrial
0 1.50
CCUS (1 MTCO2e Reduction eq)
(blank)
100-200MMBtu/hr-Industrial
N CCUS (1 MTCO2e Reduction eq)
0 1.00 (blank)
50-100MMBtu/hr-Industrial CCUS
(1 MTCO2e Reduction eq) (blank)
I 25-50MMBtu/hr-Industrial CCUS
0.50 (1 MTCO2e Reduction eq) (blank)
■ 2 MMB hr-In ri under 5 tu/ dustI a
1 1 1 1 1 1 1 1 1 1 CCUS (1 MTCO2e Reduction eq)
e e e e (blank)
0.00
O ti CO O O r N M It LO W 1` 00 O O r N M le LO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Years 2025-2045 2025 Natural Gas IRP Appendix /��■ 808
16 **No Volumes will be available until 2030

Daily Modeled Volumes
2025 Natural Gas IRP Appendix 809
�IIIIV�STa®

H2 - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
100,000 35
■Blue Hydrogen 1
90,000 ■Green H2-Wind+Electrolysis 1 N 30
■Green H2-Solar+Electrolysis 1
80,000 -Microwave Pyrolysis 1 O
R 70,000 25
60,000 20
sCr
50,000
° 40,000 15
30,000
10
20,000 C
10,000 Q 5
tD 1N O O O N M In O M O O O N M In
N N N N M M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*H2 will be limited by volume to 20% regardless of availability 2025 Natural Gas IRP Appendix 810
18 **No volumes will be available until 2030 AMISTA®

SM - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
25,000 10
9
20,000 0 8
7
15,000 6
� a 5
10,000 4
o �
3
5,000 2
- Q 1 � ■ 1 1
N N N N M M M M M M M M M M CO 1` QQ a) CD N M � 0 CO I,- Co a) O NM It 0
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o N N N N M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
Biomass 1 Biomass 2 Biomass 3 Green H2-BiogenicCO2 1
*SM is limited to NW Technical Potential availability &Avista share bAWdQf3j8RfijpQpeffl hers 811
.0
19 **No volumes will be available until 2030 VISTA®

RNG - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
14,000 6
12,000 — N
• o
5
10,000
- 4
8,000 '
Cr 3
6,000
4,000 2� ' � �
2,000 1 ' ■ ■ ' ' Q 1
O O O O O O O O O O O O O O O O O O O O N N N N M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
RNG -AM 4 RNG -AM 5 RNG - FW 3 ■RNG - LFG 1 RNG - LFG 2
RNG - LFG 3 ■RNG - LFG 4 RNG - LFG 5 RNG -WW 1 RNG -WW 2
RNG -WW 3 RNG -WW 4 RNG -WW 5
*Quantities not available until 2030 2025 Natural Gas IRP Appendix 812
20 **Removal of high priced RNG prior to modeling (AM 1-3, FW1-2) �iliVISTA®

RTC - Modeled Volumes
NW Only
Daily Volumes Annual Volumes
Available in CROME
100,000 ' ` 40
90,000 _ - v, 35
80,000 r-
•° 30
70,000
60,000 _ 25
� I I
CL 50,000 _ 20
0 40,000
30,000 _ — ' ' ' 15
I
20,000 10 �
10,000 _ ■ ■ ' a 5
-
0 0 0 o a a a a a a a a a a o 0 0 0 0 o to ti 00 M O N MIRT LO (0 ti 00 M O N M 11 LO
N N N N N N N N N N N N N N N N N N N N N N N N M M M M M M M M M M
RTC(RNG-AM 4) RTC(RNG-AM 5) RTC(RNG-FW 3) ■RTC(RNG-LFG 1) RTC(RNG-LFG 2) O O O O O O O O O O O O O O O O O O O O
RTC(RNG-LFG 3) RTC(RNG-LFG 4) RTC(RNG-LFG 5) RTC(RNG-WW 1) RTC(RNG-WW 2) N N N N N N N N N N N N N N N N N N N N
RTC(RNG-WW 3) RTC(RNG-WW 4) RTC(RNG-WW 5)
*Quantities are available to the model in 2026 2025 Natural Gas IRP Appendix 813
21 **Removal of high priced RTCs prior to modeling (AM 1-3, FW1-2) .A VISTA

CCUS
NW Only
Daily Volumes Annual Volumes (MTCO2e)
Available in CROME 2,500,000
7,000 Industrial CCUS ■DAC
6,000
2,000,000
5,000
N
0 4,000
L 0 1,500,000
a 3,000
0 2,000 = 1,000,000
c
1,000 Q
500,000
CG h 00 O) O N M 1* LO CO r 00 O O N M LO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
under 25MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) 25-50MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) W ti 00 M O r N CO q* LC) W ti 00 0) O r N M q* Lf)
50-100MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) 100-200MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) N N N N M M M M M M M M M M leqCt q* V q1 qe
O O O O O O O O O O O O O O O O O O O O
200-400MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) 800-1600MMBtu/hr-Industrial CCUS(1MTCO2e Reduction eq) N N N N N N N N N N N N N N N N N N N N
■Direct Air Capture-DAC CCUS(1 MTCO2e Reduction eq)
*No Volumes will be available until 2030 2025 Natural Gas IRP Appendix 814 AM
22 **CCUS "Industrial" is based on Avista specific high-volume custom, SM

Annual = Modeled Volumes vs . Technical Potential
Volumes
% of Modeled Volumes vs. Technical Potential** % of Modeled Available Volumes in CROME by Type*
1,400 Technical Potential Total 12% 100% I
■ Modeled Available Volumes Total d 90%
1,200 — Modeled %of Technical Potential °
10/o ca 80%
c a 70%
9 1,000 8% v Q 60%
s 800 c 40%
600 0 30%
4% O 20%
Q 400 _d o 10%
� o
2% 0 0%
2OO I 0 CG 1I- OD O O N M Iq O to 1- 00 0) O � NM 11 O
- N N N N M M M M M M M M M M I* I* I* I* q* N*
• N N N N N N N N N N N N N N N N N N N N
_ o
CO1- 00 0) OrNMleOOti00OO NM � 0o CCUS (Dtheq) H2 RNG RTC SM
O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N
*Technical Potential Volumes are from ICF and weighted to % shaw2efvL of 4�aers for National and NW volumes, 815
23 meaning this would be Avista's share of those volumes 'ediI Vasma

Other Supply Side Resource Options
2025 Natural Gas IRP Appendix 816
�IIIIV�STa

Propane Storage
• CapEX - $14.7MM (20 Year Asset Life) Available in CROME
$225
• Plant Size — 30M Dth (1 cycle) $200 i Fixed Costs ■Variable Costs
• Installation + Owners costs — 5% of capital $175
cost
$150
• Delivery Cost is included $125
• Plant electricity and air injection .o $100
• Siting, permitting and build - 2 years Z $75
$50
• Propane costs per gallon are included in $50
estimated nominal $ per Dth — Variable $_
Costs N N N N M M M CO) M LO M M M M M CD Cq CO) � LO
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
*Cycling of plant reduces overall cost per Dth 2025 Natural Gas IRP Appendix ■ 817
�/��ui
25 **No volumes will be available until 2028 1n.5m ®

Liquified Natural Gas ( LNG) Peak Storage
• CapEX - $200MM (50 Year Asset Life — $70 Available in CROME
Avista Rev. Req) ■ Fixed Cost Variable Cost*
• Plant Size — 1 Bcf $60
• Max volume per day 103 700Dth
p Y — � � $50
• Pipeline - $2MM
0
Q $40
• Utility Interconnect - $3. 12MM
• Installation + Owners costs — 30% of capital $30
• Liquefaction Costs Z $20
• Days of peak supply — 10 $10
• Liquefier capacity per day — 7,000 Dth
$Siting, permitting and build - 4 years
• W I,- W M CDr N M � 0 W I- W M CDA N M � 0
N N N N M M M M M M M M M M � � � � � �
CDO CD CD CD O CD CD CD CD CD CD CD CDO O O O O O
• Gas commodity costs included in CROME N N N N N N N N N N N N N N N N N N N N
and combined with estimated nominal $ per *Example only as costs are modeled directly in CROME
Dth
*Cycling of plant reduces overall cost per Dth 2025 Natural Gas IRP Appendix �� 818
26 **No volumes will be available until 2030 ���IIiIrmsm ®

Constraints of Resource options in CROME
Resource •e F'--Eu- Volurnetric Restrictionof Availability
Allowances 10% of Market per program rules (CCA) 2026
Community Climate Investments 15% (2025-2027), 20% 2028+ (CPP) 2026
Demand Response CPA from AEG for potential 2026
Electrification No constraints, up to total energy demanded on 2026
LDC by area/class/year
Energy Efficiency CPA from AEG and ETO 2026
Renewable Thermal Credit NW Technical Potential (ICF) —Avista Share (16%) 2026
Propane Storage 30,000 Dth 2028
Hydrogen NW Technical Potential (ICF) & Avista Share (16%) 2030
& 20% by volume
Synthetic Methane NW Technical Potential (ICF) & Avista Share (16%) 2030
Renewable Natural Gas NW Technical Potential (ICF) & Avista Share (16%) 2030
Liquified Natural Gas 1 Bcf Total & 0.1 Bcf Daily W/D 2030
Carbon Capture, Utilization and Storage 2030
ConstrairdS5tOAWAtW t iXvolume customers (ICF) 819
27 A', TA®

ft
PR
2025 Natural Gas IRP Appendix 820
1

High Level Modeling Overview
Deterministic Portfolio Optimization — (For All Alternative Scenarios)
-Portfolio solves for 1 future using expected value assumptions/inputs for each data point in the model
-The solve is optimized/valued against constraints:
•CCA
•CPP
-Transport
-Resource and Volumetric availability
�. .. Vn
-Portfolio solves for 5 futures simultaneously representing a distribution of choices across varying load profiles, prices and constraints to create the
final resource selections
•Avista may test multiple additional futures to arrive at the final PRS
Monte Carlo of a single portfolio— (Selected Scenarios)
•CROME locks down the resources selected in each portfolio scenario
•A set of 500 Monte Carlo simulations of load, weather, fuel prices and availability
-will be run to measure variation of prices, risk and availability to serving load and meeting required constraints
Monte Carlo portfolio optimization — (PRS Unconstrained)
•500 individual portfolios
-Provide Statistics of 500 portfolio resource selections
2025 Natural Gas IRP Appendix 821
DRAFT A VISM

Net Load and Energy Efficiency
Avg. Net Load After EE EE Cumulative Reduction
50 6
45 ■WA ID ■OR WA Tprt ■OR Tprt ■WA ID ■OR WA Tprt ■OR Tprt
� 40 c 5
3 °5 4
30
25 3
0 20 c'
15 M 2
z 10
� 1
5 0
C0 1- 00 0-) O — N M1:T V) (0 r- 00 0) O N CO IZT L� (.0 r— 00 0') O N CO It L O 1— 00 0-) O N M � U')
N N N N M M M M M M M M M M "t It It � lzt T N N N N CO CO CO M M M CO CO CO CO It ItI'* ItIt It
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 822
3 DRAFT �u Viszff

Selected Resources
1 .50 4.00
_ - RNG - LFG 3 RNG - LFG 4
L ■ - ' ' - _ _ �, ■ RNG - LFG 5 RNG - WW 5
0 1 .00 ' ' 6 3.00
0� o
Q 2.00
0.50
0 , o
U
0.00 1 .00
C0I- COM0 NMzzj- LOCDI` COMOrNM "ZI- LO
O O O O O O O N O 0 0 0 0 0 0 0 0 0 0 0 Q
0.00
Allowances (Free) Allowances (Given) CO CO M O N CO lzl- Ln CO CO M O N CY) :t LO
Allowances (Purchased) +CCI NNNNMMMMMCOCOCMMMNJ- ItItItItIt
200-400MMBtu/hr-Industrial CCUS i800-1600MMBtu/hr-Industrial CCUS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
■Prior Contracted RTCs ■Alt Fuels (MTCO2e)
2025 Natural Gas IRP Appendix 823
4 DRAFT �iIVISTA®

Net Emissions
0.008 0.001 1.4
N20 ■CH4 ■CO2
0.007 0.001
1.2
0 0.006 0 0.001 I 4
0
0.001
.005 _ 1.0
0.001 0.8
N 0.004 N N
O 0 0.000 0 0.6
U 0.003 U U
0.000 0.4
0.002 0.000
0.001 0.000 ■ 0.2
0.000 0.000 0.0
CO f-- M O O N M 't LO CO Ih M O O N M 't M (O Il- M O O N M In CO 1- CO M O N M �t M CO I- M M O N M V M CO I- M O O N M LO
N N N N co M M M M M M M M M V V T V V V N N N N M M M M M M M M M M V V V V V V N N N N co M MMMMMM M M V V V V V V
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O (D O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1.4
■CO2 CH4 N20
1.2
U)
c
° 1.0
.S 0.8
a>
O 0.6
U
0.4
0.2
0.0I ,l1,(()) I� �p
N N aN0 N cM co 2t*Y 'L"5 SC") ItNF�I t It 't It It 824
5 DRAFT o0000000000000000000

NEI
• Added to the Price of Natural
Gas 0 $1.60
$1 .40
Safety incidents
m r $1 .20
Carbon monoxide poisoning C o $1.00
o �
$0.80
Co p
0 $0.60
• Social Cost of Carbon 0 $0.40
o �
U $0.20
• Emissions $-
CO I` M M O — N M t LO CO I` W M O — N M t LO
N N N N M M M M M M M M M M It It It It It It
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 825
6 DRAFT 'edu Visma

Economic Benefit of RNG Selected
$3.0 3
o RNG - LFG 3 ■RNG - LFG 4 RNG - LFG 3 RNG - LFG 4
$2.5 RNG - LFG 5 ■RNG - WW 5 0 2.5 RNG - LFG 5 RNG - WW 5
c �
$2.0 m 2
C
>
U $1.5 S 1.5
E o
o $1.0 1 ,
w
m
$0.5 0.5 I
U
$0.0 0
CO r,- 00 M O N CO It LO (0 r- 00 M C) N CO �t LO (0 r— 00 0') O N M ,I- LO (0 r� 00 0') O N M ,I- LO
N N N N M M M M M M M M M M It It 'IT N N N N M CM M CM M CM CO CM M CM It 'IT It 'IT
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O C7
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 826
7 DRAFT �iI iVISTA®
Source: IMPLAN based on selected resources

System Cost and Rate Impact
$300 $3.00
PGA Rate Impact Base Rate Impact
$250 $2.50
$200 E $2.00
0
2 $150 i $1 .50
a) I
a $100 $1 .00
z
$50 $0.50
I
$- $-
CO Il— M M O — N M I L() CO [` M M O — N MI- U) Cfl f` 00 M O N M I LO CD I` 00 O O N M I LO
N N N N M M M M M M M M M M � � It 't � NT N N N N M M M M M M M M M M I It It It It
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
*Does not include all Tariff Riders
2025 Natural Gas IRP Appendix 827
8 DRAFT �iliVISTA®

Allpi'ISTA°
Alternative Scenarios and
Sensitivities
DRAFT

Alternatmive Scenarmios
2025 Natural Gas IRP Appendix 829
�IIIIV�STa�

Scenario Description Changesfrom
SCC @ 2.5% SCC in All Jurisdictions
Social Cost of Carbon
50 4.00
■WA ■ ID ■OR WA Tprt ■OR Tprt
CO 40 — c 3.00
0 .0
30 — 2.00 '
20 0 1.00 ' � � � PM
J to
■ ■_ ■_
N N - X
z 10 0.00 r
CO A M M CD N M I Lf') CO rI- 0p M O N M I LO
N N N N CO M M M M M M M M M � � � 't 't
Q O O O O O O O O O O O O O O O O O O O O
NNNNOMMMMMMMMMM � � � � � � RNG - LFG2 RNG - LFG3 RNG - LFG4
N N N N N N N N N N N N N N N N N N N N ■ RNG - LFG5 RNG - WW4 RNG - WW5
u) 2.00
c
0
1 .50 - 1.2 CO2 CH4 N20 Upstream CH4
1.00 ' 0
1.0
qjiii2i 0.8
0.50 ■ ■ ■ ■ ■ ■ m 0.6 ■
N
N 0.00 0
(.0Il- 000') O NMItLOCOIl- 00M0 — NM ::I- LO 0.4
U N N N N CO M M M M M M M M M 't ItIt It
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
0.2
Allowances(Free) Allowances(Given)
Allowances(Purchased) CCI 0.0
800-1600MMBtu/hr-Industrial CCUS ■Prior Contracted RTCs 2025 Natural Gas IRP Appendix(D ti 00 O O N CO It LO CO rl- 00 O') O N CO 't LO 830
Alt Fuels (MTCO2e) o0000000000000000000 �ili1�/�STa®
N N N N N N N N N N N N N N N N N N N N

Scenario Description Changesfrom PRS
Hybrid Heating from PRS 0 LDC Heating @ 381 F
Loads 0 Avista Electric Resources for New Loads (ID/WA)
Hybrid Heating
50 2.00
WA ID OR WA Tprt ■ OR Tprt ■ RNG - LFG 5
40 0
o —_
2 30
c
1.00
cz 0 20 0
J
a' 10 Ui
z
_ Q
CO 1- 00 O CD N CO u7 COrl- 00 M CDN M t LO O.O O
N N N N co co M co M c'o M M M M It ItIt tltllt Cfl r1- 00 M O N CO I LO Cfl r1- 00 M O — N M I LC)
O O O O O O O O O O O O O O O O O O O O N N N N M M M M M M M M M M � � � I'll
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
1 .50 _ 1.4
0 CO2
— — — 1.2
M 1 .00 k6-- c
0.50 ' Is0.8
a) 11 � 0 ■ ■ ■ M � N 0.6
N 0 '0.00 T T T T 0.4
CO f` 00 M O N M I LO CO ti 00 M O N M "t LO
N N N N M M M M M M M M M M I 't 't 't 't
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.2
N N N N N N N N N N N N N N N N N N N N
Allowances (Free) Allowances (Given) 0.0
Allowances (Purchased) CCI c0 ti 00 0-) 0 N CO ":I- LO c0 r` 00 0') CD N CO LO
2025 Natural Gas IRP&1 4ixN NCO COMM co M M M M M "t � It It � 831
■800 1600MMBtu/hr-Industrial CCUS ■Prior Contracted RTCs CD O CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD4 /III
■AltFuels (MTCO2e) NNNNNNNNNNNNNNNNNNNN AMISTA®

Scenario Description Changesfrom PRS
Higher than expected load growth High Load Demand
High Growth
50 WA i ID OR WA Tprt ■OR Tprt 4.00 RNG - LFG 3 RNG - LFG 4
■ RNG - LFG 5 RNG - WW 5
0 40 3.00
30 - Orr
� o
2.00
0 20
J
z 10 ti 1.00
Q
- 0.00
O ti 00 M O N M � U-) O ti 00 CM O — N CO LO O ti M M O N M 't LC) O ti M M O — N M "tU-)
N N N N co CY) CY) CY) CY) CY) CY) CY) CY) CY) 1:111:111:111:111:11 N N N N co co co co M co co M M co 1:11 � � 1:111�11
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1.4
1.50 CO2 CH4 N20
- - - ' 1.2
1.00 ° 1.0
0.8
0.50 0.6
Q) ' 0 0.4
NO 0.00
U (9 Il- 00 M C) N M ,zJ- LO CO I— M M C) cl CO 't U-) O.2
N N N N M M M M M M M M M M I It It It It
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N O.O
Allowances(Free) Allowances(Given) (.0 ti M M O N M "t LO C9 ti M M O — N M I u7
Allowances(Purchased) ■CCI N N N N co co co co co co co M co M � � � � � It
200 400MMBtu/hr-Industrial CCUS ■800-1600MMBtu/hr-Industrial CCUS 2025 Natural Gas IRP AppegixO CD CD CD CD C) CD CD CD CD CD CD CD CD CD CD CD CD CD832
NNNNNNNNNNNNNNNNNNNN �IIII�IISTA®
■Prior Contracted RTCs ■Alt Fuels (MTCO2e)

Scenario Description Changesfrom PRS
Climate Programs Cost Impact to System No Climate Programs (CCA,CPP)
No Climate Programs
50
■WA ID OR WA Tprt ■ OR Tprt
40
0
30 ,
c
m 2
c� 0
0
J
z 10
CO ti 00 O') O N M � LO (D r` M M O N M I LO
N N N N co M M M M M M M M M � � � � 'ZI,
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
Cn 0.01 3.0
0.01 - CO2 -CH4 N20
■Prior Contracted U) 2.5
75 0.01 RTCs o
2.0
0.01
0.01 N 1.5
O 0.00 1.0
0.00 0.5
0.00
COf� 000� O � NM � LOCOI1- 00MCD — NM � LO 0.0
N N N N M M M co co M co co M M It It It � ;I- Itf o p M O � N M � � CO f� 0 0 M O � N M � I>7
O O O O O O O CD CD CD O O O O O O O O O O 2025 Natural Gas IRP AppendiP N N N M M M M M M M M M M � � � � � � 833
NNNNNNNNNNNNNNNNNNNN
NNNNNNNNNNNNNNNNNN CIA N �III�IISTA®

Scenario Description Changesfrom
Higher than expected load shift to the power grid Lowest Load Demand
High Electrification
50 m WA ■ ID OR WA Tprt ■OR Tprt 0.20 ■ RNG - LFG 5
c
0 40 0.15
30
� o
0.10
0 20
J
10 0.05
z
Q
- 0.00
co Il- c0 M O N M � U-) O ti c0 M O N M I U-) O I'- M M O N M 't LC) O ti CO M O N M "tU-)
N N N N M M M M M M M M M M N N N N M M M M M M M M M M � � � � 1:11
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1.50 1.4
o — — CO2 CH4 N20
- 1.2
U)
1.00 — — 0 1.0
■
■ ■ ■ ■
°v)) 0.8
0.50 ■ ■
0 0.6
0
N � 1
0.00
CO I` 00 M O N CO LO (0 I1- 00 M CD CO � U-) 2 O.4
N N N N co co co co co co M M M M It It ItIZI- ItIt
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 02
N N N N N N N N N N N N N N N N N N N N
Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) ■CCI CO I— 00 0 0 N CO It Ln CD 1 - 00 0 0 N CO 't Ln
200-400MMBtu/hr-Industrial CCUS ■800-1600MMBtu/hr-Industrial CCUS 2025 Natural Gas IRP AppeSlbg N N co M M M co co co M M M I It It It It 834
■Prior Contracted RTCs ■Alt Fuels (MTCO2e) N O O O O CD O CD O O CD O CDN N O 0 0 0 /III_
�II��/ISTA®

Scenario Description Changesfrom
Low Natural Gas Use RCP 8.5 Weather
• 95t" Percentile of Natural Gas Prices
Low Natural Gcolb Ust 9 Percentile Allowance Prices
• Loo w Alt Fuel Volumes— 5t" Percentile
• High Alt Fuel Prices—95t" Percentile
50 ■WA ■ ID ■OR WA Tprt ■ OR Tprt U) 3.00 RNG - LFG 4 ■ RNG - LFG 5
c
c 40 0
o —
2.00
30
0 20
U) 1.00
z 10 U- ,
Q
- i I I I I I I I 1 0.00
CO rl- 00 M O N M 'tU-) CO rl- 00 M O N M 'tU-) CO � 00 O O N M � LO CO rI- 00 M O N M :I- LO
N N N N M M M M M M M M M M � � � � � IZI- N N N N M M M M M M M M M M ;I- It Nt It Nt Nt
O O O O O O O O O O O O O O O O O O O O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1.50 — — 1.4
O — — — — CO2 CH4 N20
1.2
— _
1.00 — c'
0.50 • � ■ ■ , 0.8
1111 ■ ■ ■ ■ 0 0.6
N 0.00 U '
OU c0r,- MMO NM � LO (O rl- 00MC) NM ,:I- LO � 0.4
N N N N M M M M M M M M M M I It � It It
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N 0'2
Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) +CCI (D ti 00 rn O N M "t LO (D ti 00 rn O N M 't u7
200 400MMBtu/hr-Industrial CCUS ■800-1600MM13tu/hr-Industrial CCUS 2025 Natural Gas IRP AppegixON O O O O O O O O O O o O O O O O O O 835
■Prior Contracted RTCs ■Alt Fuels (MTCO2e) N N N N N N N N N N N N N N N N N N N N /III Dui I/ISTA®

Sens 'it 'iv 'ity
2025 Natural Gas IRP Appendix 836
�IIIIV�STa

Scenario Description Changesfrom PRS
Average Case with Historic Use ' 3 Year Use Per Customer
and 20 Year Rolling Daily Weather 20 Year Rolling Daily Weather
Average Case
4.00
50 WA ID OR WA Tprt ■ OR Tprt
c c 3.00
2 40
75 30 2.00
._ '0 20 1.00 1600
z 10 0.00
CD rI- M M O N M I LC') CD rI- M M O N M I V)
Q N N N N M M M M M M M M M M ' 'IT II- It 'IT
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
CD r1- 00 M O N CO 't u7 CD r— 00 0) 0 N M 't LO
0000000000000000000o RNG - LFG2 RNG - LFG3 RNG - LFG4
NNNNNNNNNNNNNNNNNNNN ■ RNG - LFG5 RNG - WW4 RNG - WW5
2.00 1.4
o _ ■CO2 CH4 N20
1.50 1.2
75
1.00
■ 0.8
O cv 50
0.6
N = � � � O
0 0.00 0.4
U C0ti00M0 NMqLOCDr— Ood) O NM 'tu7
N N N N co co co co M co M co co M It It It It It It
00000000000000000000 0.2
N N N N N N N N N N N N N N N N N N N N
Allowances(Free) Allowances(Given) 0.0
Allowances (Purchased) CCI 2025 Natural Gas IRP Appen(D ti 00 0') O N CO �t LO C9 ti 00 0-) O N cM 't LO 837
800-1600MMBtu/hr-Industrial CCUS ■Prior Contracted RTCs N CV CV CV CM M M M M CM CO CO M M � /III_
Alt Fuels (MTCO2e) N N N N N N O O N N N N N O O N N N N N �IIIVISTa®

Scenario Description Changesfrom
High Cost of Alternative Physical Fuels High Prices of RNG,SM,H2
High Alternative Fuel Costs
50 2.00
■WA ■ ID ■OR WA Tprt ■OR Tprt L RNG - LFG 4 ■ RNG - LFG 5
40
c �
0 0
30
1.00
co 0 20 �-
p
J
i
z 10 N
U-
W11MMb _�
Cfl r- 00 O O — N M :T U') CO r- CO M O — N M LO Q 0.00
N N N N M M M M M M M M M M � � COr` OpOO NM � Il7Cflr- 00d� O NM � In
O O O O O O O O O O O O O O O O O O O O N N N N M M M M M M M M M M
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
cn 1.50 1.4
o _ — ■CO2 ■CH4 N20
■ _ � � � _ � ' 1.2
1.00
1.0
0.50 0.8
0 ci 0.6
0) ■ O
IN 0.00 () 0.4
U C0
r` oO (MO ,r- NMttLO (0r- W M C) NM 'IT L
N N N N M M M M M M M M M M � IT T � 'IT 'T
N O O O N O O O O N N N N O 0 0 0 0 0 0 0.2
■Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) ■CCI 2025 Natural Gas IRP Append ti M O CD M � LO Cfl 1- 00 O O N M 't LO 838
11 200-400MMBtu/hr-Industrial CCUS ■800-1600MMBtu/hr-Industrial CCUS R N N N M M M M M M M M M M t t t t t �n
■Prior Contracted RTCs ■Alt Fuels MTCO2e CD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 �III�/MSTA®
( ) N N N N N N N N N N N N N N N N N N N N

Scenario Description Changesfrom
High Costs of CCAAllowances 95th Percentile of Expected CCA Costs
High CCA CoS fr
50 3.00
45 WA ID OR WA Tprt ■OR Tprt RNG - LFG 4 ■ RNG - LFG 5
c 40
°_ 35 0
30 2.00
25
0 20 0
15 1 .00
z 10 0
5
- Q 0.00
CO I� 00 M O N M �t U') CD I� Co M O N M I. U) (0I� 000O — NMI InC9I-- 00 CT) O NMzl- In
N N N N co co M M co M co M M M � ItIt It IZI- N N N N M M M M M co M M M MIt It It 'tIZI- 't
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1.50 1.4
o — — — — — — CO2 CH4 N20
L 1.2
1.00
4 0.50 0.8
Q) ■ ■ ■ ■ � ■ ■ ■ � � � N 0.6
N 0
O 0.00 0.4
CflI� 000� O NM � � COf� MOO NM � �
N N N N co co co co co M co M M co Iti- It 't ,:I- � ItI,
75 O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N 0.2
Allowances(Free) Allowances(Given)
Allowances(Purchased) CCI 2025 Natural Gas IRP 4pQndi 839
200-400MMBtu/hr-Industrial CCUS 800-1600MMBtu/hr-Industrial CCUS co ti M O O N M M M O O 't CV M 't 't /III
2 N N N N M M M M M M M M M M M M M M � � � � � AdVISTAW
■Prior Contracted RTCs Alt Fuels (MTCO2e) O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N

Scenario Description Changesfrom PRS
High Costs of Natural Gas 95th Percentile of Stochastic Prices
High Natural Gas Prices
50 4.00
WA ID OR WA Tprt ■ OR Tprt RNG - LFG 2 RNG - LFG 3 RNG - LFG 4
40 c ■RNG - LFG 5 RNG -WW 4 RNG -WW 5
0 0 3.00
2 30
2.00
0 20 0
J
z 10 � 1.00
- 0.00
CO ti 00 M O N M I u7 CO rl- 00 M O N M It LO c0 ti a0 M O N M I LO CD r— 00 M O N M It LO
N N N N M M M M M M M M M M It It It 't 't 't N N N N co co M co co co co M co MIZI- It � IZI- It It
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1.50 1.4
o — — _ _ CO2 CH4 N20
_ 1 .2
1.00 -
- 0 1.0
0.50 ' — 0.8
O I11 � ■ • NINE N 0.6
a�
0 0.00 0.4
U COIl- 000O NM ::I- LOCOrl- 00MCD — NMI LO
N N N N M M M M M M M M M M ITI:T NT It NT IT
OOOOOOOOOOOOOOOOOOOo 0.2
Allowances (Free) Allowances(Given)
Allowances (Purchased) CCI 0.0 11 7 1 ,N
2025 Natural Gas IRP Apperk%ti 00 O O N M 't LO CO ti 00 0') O — N CO 't LO 840
800-1600MMBtu/hr-Industrial CCUS ■Prior Contracted RTCs N N N N M M M M M CY) M M M M I:T I:T I:T I:T I:T I:T
13 Alt Fuels (MTCO2e) 00000000000000000000 �III�IISTA®
N N N N N N N N N N N N N N N N N N N N

Scenario Description Changesfrom PRS
Higher Loads for WA-Com Adjusts Loads to Estimate Changes
to WA State Building Codes
Initiative 2066
50 E WA ID OR WA Tprt ■OR Tprt 4.00
RNG - LFG 3 RNG - LFG 4
c 40 — c ■RNG - LFG 5 RNG - WW 5
0 3.00 —
c
30
0 20 2.00
J
z 10 L 1.00
- Q
Co I� 00 0') o N CO LO CO I` 00 0') o N CO LO 0.00
N N N N co M co CO M co M co co M -It � zl. 't 't 't CO f1- CO O O � N M Ln CO fl- CO M O r N MI- L0
0 0 0 0 0 0 0 0 0 0 0 O O O O O O O O O N N N N M M M M M M M M M M � ":I- 't 't 't �
N N N N N N N N N N N N N N N N N N N N o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
w 1.50 1.4
� — _ _ _ _ CO2 CH4 N20
■ � , 1.2
1.00 �
' ° 1.0
in 0.50 " 0.8
0 ONE
a�
11
0 0.00 U 0.4
U cor,- MMCD NM � U-) COf� 00MCD M "tU-)
N N N N M M M M M M M M M M ItIt It It I
o0000000000000000000 02
Allowances (Free) Allowances (Given)
Allowances (Purchased) CCI 0.0
200-400MMBtu/hr-Industrial CCUS 800-1600MMBtu/hr-Industrial CCUS 2025 Natural Gas IRP AppeRix CN OM co M c9 � � It 't 841
14 0Prior Contracted RTCs Alt Fuels (MTCO2e) CD CD CD CD CD O CD CD CD CD /III_
N N N N N N N N N N �III�/MSTA®

Scenario Description Changesfrom
Lower Costs of Alt Fuels 5th Percentile Costs for RNG, SM, H2
Low Alternative Fuel Costs
50 WA - ID OR WA Tprt ■OR Tprt 3.00 RNG - LFG 3 RNG - LFG 4
c 40 U) ■ RNG - LFG 5 RNG - WW 5
0 0
30 2.00
c �
m 20 0
0 ,
J 1.00
z 10
Q
CD I� 00 M O N CO M O ti CO M O N M 'tU') 0.00
N N N N M M M M M M M M M MIt 't 't CO ti 00 M O N M I Ln co � 00 M O (N M U')
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N N N N M M M M M M co M M M �
N N N N N N N N N N N N N N N N N N N N O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
c 1.50 —
o — — 1.4
CO2 CH4 N20
1.00 - c 1.2
0 1.0
W
4 0.50 0.8
_ 0.6
0 0.00 _ _
NNNNOCOCOCOCOCCCOMCMMMM � It � � It � � O.4
75 O O O O N O O N O O CD O O O O O O N O O 0.2
Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) CCI cDl` 0007') O NMItLO (Dr- 000') O NM 'tIf)
200-400MMBtu/hr-Industrial CCUS 800-1600MMBtu/hr-Industrial CCUS 2025 Natural Gas IRP Appe0diXN N cV M M C'M M M cM CO M M M zl- 842
15 ■Prior Contracted RTCs Alt Fuels (MTCO2e) NO O CD CD ON ON NO NO 0 0 CD ON ON NO NO o 0 CD ON 0 /III_
Dui M/ISTA®

Scenario Description Changesfrom
Expected Futures Using 6.5 Weather Futures 6.5 Weather Futures
RCP 6 . 5
50 4.00
45 WA ID OR WA Tprt ■OR Tprt RNG - LFG 3 RNG - LFG 4
40 c ■RNG - LFG 5 RNG - WW 5
0 35 0 3.00
30
25 2.00
0 20
15
z 10 =3 1.00
LL
5 Q
0.00
C0 ti 00 O') O � N M "t L0 co r,- 00 0') O � N M 't M (.fl ti 00 0') O — N CO 'IT L0 Q0 ti M M O — N M T M
N N N N M M M M M M M M M M � 't 't IZI- N N N N M M M M M M M M M M � 'IT � �
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N (N N N N N N N N N N N N N N N N N N N N N N
1.4
u) 1 .50 _ CO2 CH4 N2
o — — , _ _ 1.2
1 .00 ' ° 1.0
c � —
(n
0.8
O 0.50 I ■ ■ ■ ■ _ N 0.6
_ 1 O
0
O 0.00 0.4
(0 r` 00 M O — N CO U-) O r1- 00 0') O N M 'ZI, V7
N N N N M M M M M M M M M M � � IZI, 0.2
75 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N
Allowances(Free) Allowances(Given) pen
Allowances Purchased CCI 2025 Natural Gas IRP Appendix C0 04 00 O O � N cM CO � C0 M M O O t N CO t t 843
(Purchased) NNNNMMMMMMMMMM � � � � � � /III 16 200-400MMBtu/hr-Industrial CCUS 800-1600MMBtu/hr-Industrial CCUS CD O CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD AIM STa®
N N N N N N N N N N N N N N N N N N N N
■Prior Contracted RTCs

Scenario Description Changesfrom
Expected Futures Using 8.5 Weather Futures 8.5 Weather Futures
RCP 8 . 5
50 4.00
I WA ID OR WA Tprt ■OR Tprt RNG - LFG 3 RNG - LFG 4
c 40 - ■ RNG - LFG 5 RNG - WW 5
0 0 3.00
30
2.00
0 20 0
J
i
z 10 1.00 I
- Q 0.00 ML I I 1 1
CO ti 00 O O N M :T U) CO ti 00 O O N M � U-) Cflr- 00MO — NMzl- InC0rl- M M C) — NMtU-)
N N N N M M M M M M M M M M I NT � � I:T N N N N M M M M M M M M M MIt It IZI- 't Nt "Zi-
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
1 .50 1.4
o — — CO2 CH4 N20
1 .00
c 0 1.0
0.50 ' 0.8
O
0 0.00 0.4
U (9tico0-) O NM �tLOCOr` COMC) NM "tL
N N N N co co co co co co co M M M It ":I- 'tIt It I
CD CD CD CD CD CD CD CD CD CD CD CD 0 CD CD CD CD CD CD CD
N N N N N N N N N N N N N N N N N N N N 0.2
Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) CCI ppen r- 00 0 0 N M � LO CO r- 00 0 0 N CO L0 844
200-400MMBtu/hr-Industrial CCUS 800-1600MMBtu/hr-Industrial CCUS 2025 Natural Gas IRP Adi N N N M M M M M M M M co MIt It NJ- It It It
00000000000000000000
7 ■Prior Contracted RTCs Alt Fuels (MTCO2e) N N N N N N N N N N N N N N N N N N N N �IIIV�STa®

Scenario Description Changesfrom
Expected Futures Using 6.5 Western Natural Gas Resources
Weather Futures unavailable in Winter (Sumas,St2,JP)
Resiliency
50
■WA ■ ID ■OR WA Tprt ■OR Tprt 16.00
14.00 - M M IM �
0 0
40 12.00
30 10.00
c p 8.00 i
0 20 4.00 � � � � , �
LL 2.00
z 10 Q
0.00
O r1— M M O N M T M C0 rl— 00 M O N M LO
N N N N M M M M M M M M M M I � It It
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
CD f— M M O N M I M CD I- M M O N M 't LO
N N N N CO CO CO CO CO CO CO M CO CO t t d' t t t ■Blue Hydrogen 1 ■GreenH2-Solar+Electrolysis 1 ■RNG -LFG 2
O O O O O O O O O O O O O O O O O O O O ■RNG -LFG 3 ■RNG -LFG 4 ■RNG -LFG 5
N N N N N N N N N N N N N N N N N N N N RNG -WW 3 RNG -WW 4 RNG -WW 5
Biomass 1 ■Biomass 2
v, 1.50 1.4
o ■CO2 ■CH4 N20
1.2
1.00 c
- - ■ 0 1.0
0.50 — 0.8
Mi 1b M M i N 0.6
N 0
0 0.00 _ _ 0 0.4 '
F- N N N N MM M M M M CM M M M M I Nt It � Nt 2
g o 0 0000000000oo0No 00 o 02 tI
M
■Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) ■CCI
800-1600MMBtu/hr-Industrial CCUS ■Prior Contracted RTCs 2025 Natural Gas IRP Appendix N N CO CO CM M CM0 - It � 845
O O O O O O O O O O /III 18 Alt Fuels(MTCO2e) N _
N N N N N N N N N �III�/�STA®

Resiliency Cont.
35,000 ■Propane Storage 8.00 ■WA-Res—Space Heat ■OR-Roseburg-Res_Space Heat
30,000 m m (n 7.00
25,000
6.00
5.00
20,000
4.00
Q 15,000
0 3.00
U 10,000 a 2.00
U
5,000 ` 1.00
a�
0 w 0.00
Cfl ti CO M O N M :T in CO I` CO M O N M I U-) CO f` CO M O N M ,zj- M CO I1- CO M O N M "tU-)
N N N N M M M M M M M M M M ,:I- 't IZI- N N N N M M M M M M M M M M � 't ":I- 't "Zi-
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 846
A
19 VISTA®

Scenario Description Changesfrom
Considers a Forced Fuel Mix RNG, SM, H2 Hard Selection
Diversified Portfolio
3.00
50
■WA ID OR WA Tprt ■OR Tprt
c
a 40 2 2.00
30
1.00
ICU 20 1111 1111
z 10 � 0.00
CO r1- W M O N M IT M M ti M O O N Mlzl- M
N IN
Q O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
Q0rl- aornO � NM 'tL000rl- 00MO 04M1:TIO ■RNG - LFG2 ■RNG - LFG3 ■ RNG - LFG4
N N N N CO CO co co co co M M M M � � � � It It
N N N N N O O O O O O O N N N O O O N N ■RNG - LFG 5 RNG - WW 4 RNG - WW 5
1.50 1.4
o — — ■CO2 CH4 N20
Cn 1.2
1.00 ' c
C
Cn 0.50 � � 0.8
O 0.6
m O
0.00 v
0.4
cor- oornO NMtLOCOrl- 00MCD NM � LO
N N N N co co co M co co co co co M ;T IT 'IT ;T IT 'IT
OOOOOOOOOOOOOOOOOOOO 0.2
F
■Allowances(Free) Allowances(Given) 0.0
Allowances(Purchased) ■CCI co rl- oo M O N CO IT LO co ti oo M O N M IT LO
800-1600MMBtu/hr-Industrial CCUS ■Prior Contracted RTCs N N N N M M M M M M M M M MI- �T NT IT 'IT
Alt Fuels MTCO2e 2025 Natural Gas IRP Appendix 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 847
20 ( ) N N N N N N N N N N N N N N N N N N N N �II�AMESTA®

All Case Compar'isons
2025 Natural Gas IRP Appendix 848
21 �I�1IVISTa

Net Load and Emissions
3.00
50 ■2026 ■2030 ■2035 ■2045 ■2026 ■2030 ■2035 ■2045
° 2.50
0
40 2.00
N
c 0
30 1.50
o �
20 0 1.00
J Ln
z 10 LU 0.50
o _
~ 0 o v LO LO cn U CO U) 0 � o 0
a 0 ° LO `° 0 c a> o -0 c oo co o 0 o C� 0 ca 3 M
o06 E ° o C9 o d U o = o U U U o U U N U a n3 U
= 0 UCL U U U U — U a) C� a> a� tY U m j
0 of U a) a� Q .92� ° LL 21 Z U CM
zcU U °> L) N o i� Q Q > = w U
_ _ _
v cn Q Q _� > w a) U 3 = Q 0 J
U °_' 2 _ 3
p J = 2 0 Z
*Includes CO2, CH4, NO2
2025 Natural Gas IRP Appendix 849
22 'AI�ISTAW

Alternative Fuels and Carbon Capture
16 300
2030 ■2035 ■2045 c 2030 ■2035 ■2045
14 250
0 12
~ 200
10
0 8 0 150
6 100
_ 4
Q I 50
2 U
' c
L 'O O C T m m to 4 w Lfl Vl (n O L C N
O C >, LO LO to � u7 (O v) (n N L C N co
s0 o c oo co E in 0 cn _o 0 U - o � c m m 2 0 0 0 .2 0 a
> m m m U U N U U a U o ca U = m � a a U U `� a U U a 0 U
o U U
p Fn
d U L O ILLi �i U t6
LL L, U = m U
0 coZ > = W p n U E Q Q a� Q L
U Q L a� Q J @ U o � _
>_ (6 O _ 0 O O J = Z J
UO O J = = J (n Z p_)
U) Z 2
2025 Natural Gas IRP Appendix 850
23 'A VISTAW

Climate Program Offset Purchases
(CCls and Allowances)
120 En 1,000
■2026 2030 2035 2045 -0 ■2026 2030 ■2035 ■2045
C: 900
c CU
Mc� 100 � 800
o °
~ 80
H 700
c .9
(n 600
m
U 60 c 500
U °
0 400
U 40 300ILI
a�
20 co 200 i
o 0 100
o g c >, u7 u7 U) c_D U)c n U) n o c6 E° oo coE " v �m
U°M o 0 O o o o C0 o °- O c L m u O ON c� U Uc
co C) U
7 .)
C) C) ° a � � o 0 a m
C0 �_ a�
° Lf LL CU !1 L L_� C.� LL � Co l l L LSD-0 U
U Q Q CM Q L O (0 Q Q L o) Q LLJ
>_ <6 U p _� 2 = >_ c6 U p
0 00 O J = = J 0 p J = = J
U) Z W Z
2025 Natural Gas IRP Appendix 851

System Cost
o $20
CQ $18
(.0 $16
o $14
N $12
$10
0 $0 8
m $6
$4
o $2 -
U $_
E -0 o c U-) LO (0 � vD co cn v) 0 c a)
gyp+ 0 taco 6 E o o 5 V ^� o cn
L LL L U U O •L U LL U O M U
_ �o U U CM —
cn U v, o a� C� a�
U cLa 0
_ _ a) U
cn o Q Q Q W 0
U E —J
(0 0 J = = J
Z
2
2025 Natural Gas IRP Appendix 852
25 �iIVISTA

Next Steps
• Confirm PRS Selection
Determine if Carbon Capture is realistically available in 2030 with TAC
Or if scenarios should not be allowed Carbon Capture until 2040 timeframe
• Run all models again based on input of deterministic results and final EE savings and
costs
• Run Alternative Scenarios through 500 Monte Carlo Futures
• Send out Draft to TAC with all available chapters and the PRS by January 31 , 2025
• Send out remaining chapters to TAC once all results from Alternative Scenarios are
finished
• Avista will accept feedback to it's Draft Gas IRP through March 9t" to incorporate into
final version of the 2025 Gas IRP document
2025 Natural Gas IRP Appendix 853
26 �II/VIVSta

10
s uri'ISTA°
Iq
Av 'lsta 2025 Natural Gas
Integrated Resource Plan

Disclaimer
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.
2025 Natural Gas IRP Appendix 855
2 eduVISTA

Integrated Resource Planning Requirements
• Public plan outlining a resource strategy to meet
future customer energy needs — a direction of Kettle Falls.
Sandpoint
S Electric ■
what the Company currently sees as the best path. • Natural Gas .
•Noxon Electric and Natural Gas ■
WASHINGTON Spokane• •Coeur d'Alene
• Must consider public input Ira Missoula
.Othello • Helena
�.. Jackson Prairie • •
Natural Gas Storage Pullman •Moscow
C
Stevenson Goldendale larkston• •Lewiston
•Grangeville
• Account for future risks Portland
La Grande•
Sa•m
IDAHO �
• Meet state policy objectives OREGON
�•Roseburg
• Conducted every 2 years Meford
•Klamath Falls
• Filed with Idaho, Oregon and Washington state
commissions
https://www.myavista.com/about-us/integrated-resource-planning
2025 Natural Gas IRP Appendix 856
3 ,edil VISTA

Firm Customer Demand by End Use
12 10
Idahc Oregon
10 4mmpwating
8 Corn-Wat
8 Com-Space Heating
w r Corn-Space Heating
O o Corn-Food Preparation 6 oRes-Water Heating N Com-Food Preparation
o r_ Res-Water Heating
._ o
4 = 4
Res-Space Heating
2 2 Res-Space Heating
0 to r� CC T O N M 4 N 1D r� CO T O N 1' N 0 �p CC p� O N M N 10 h W Oa O N M N
N N N N M M M M M M M M M M N N N N Cn M M M M M M M M a a a a
O O O O O O O O O O O O O O O O O O O O O CD O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
■Res-Appliances ■Res-Miscellaneous ■Res-Secondary Heating ■Res-Appliances ■Res-Miscellaneous ■Res-Secondary Heating
■Corn-Miscellaneous ■Ind-Miscellaneous ■Ind-Process ■Com-Miscellaneous ■Ind-Miscellaneous ■Ind-Process
■Ind-Space Heating ■Ind-Space Heating
22
20 Washington
18
16 ating
0 14 Com-Space Heating
a12 Om- oo repara ion
c 10 Res-Water Heating
8
6
4 Res-Space Heating
2
0
w 1_ co M O N M t0 t� 00 O O N M N
N N N N M C7 M M C9 C7 M M C7 CD CD Q CD CD CD
CD CD CD CD CD CD
O CD CD CD CD CD CD CD CDO CD CDO
N N N N N N N N N N N N N N N N N N N N
■Res-Appliances ■Res-Miscellaneous ■Res-Secondary Heating
■Com-Miscellaneous ■Ind-Miscellaneous ■Ind-Process
4
2025 Natural Gas IRP Appendix 857
■Ind-Space Heating III/VISTA

Green House Reduction Policies
Oregon Washington
700,000 1,400,000
CPP Cap OR Load No Cost Allowances
600,000 1,200,000 WA Load
a�
500,000 1,000,000
N
O 400,000 C, 800,000
U 0
H
300,000 600,000
200,000 400,000
100,000 200,000
CD fl- CO M O N M In CD fl- cc M O N M In CD 1l- cc M O N M In tD 1l- M M O N M In
N N N CNMMMMMMMMM M N N N N M M M M M M M M M M � I�r NrIrt Iq qq
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
Climate Protection Plan Climate Commitment Act
90% reduction by 2050 95% reduction by 2050
2025 Natural Gas IRP Appendix 858
-Figures include Transport customers where Avista has the responsibility to comply with the state program
5 �uVISTA

Clean Resources
-Renewable Natural
Gas(RNG)
-Hydrogen
-Synthetic Methane
-Carbon Capture
Utilization and Storage
(CCUS)
-Renewable Thermal
Credits
What are the options to meet our customer obligations?
Demand
Resources
-Energy Efficiency Fossil Fuel
Resources
-Demand -Natural gas
Response
-Fuel switching Reliable
Equitable
� Affordable
Infrastructure
Program / and Storage
Resources -Jackson Prairie
-Allowances Storage Facility
-Offsets -Liquified Natural
-Community Gas Storage
Climate -Propane Storage
Investments (CCI) -Interstate
Pipelines
2025 Natural Gas IRP Appendix

Volume Key:
New Resource Selections ivietric Tonne of CO2 equivalent
(Annual Average Quantity I -A 0 Therms of energy
2026 to 2030 2031 to 2039 2040 to 2045
CCI: 3,000 CCI: 11 ,000
Allowances: 576,000 Allowances: 6509000 Allowances: 671 ,000
CCUS: 983000 CCUS: 157,000
RNG: 240,000 RNG: 21100,000 RNG: 21800,000
• ID EE: 87,000 ID EE: 2409000 ID EE: 240,000
OR EE: 207,000 OR EE: 830,000 OR EE: 115577000
WA EE: 318,000 WA EE: 112209000 WA EE: 17851 ,000
' 2025 Natural Gas IRP A endix 860

Idaho Preferred Resources
12
1
W
c
0
8 Average
•
6Growth
Natural Gas
a 0.37% Natural Gas, Energy
-� Efficiency
2
W CO O O N M V LO W f-- CO O O N M .0 U,
N N N N M M M M M M M M M M V Iq Iq Iq V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 861
'eIIIIV&ST'a

Oregon Preferred Resources
12 RTCs
CCUS
v 10
c
0 Ccl
AverageRNG • •
M 8Growth
6 -0.31 % Natural Gas, Energy
CD
Efficiency, RNG, CCI,
CID 4
0
CCUS, RTCs
2 Natural
W I*- Co Cn O N M V LO CO 1` CO M O N M Iq W)
N N N N M Cn CM M M M M M M M V V V V V
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 862
"eIIIIV&ST'a

Washington Preferred Resources
30
25 � "'"Cs
V)
C
0
Icienc
zu
E 15 Allowances GrowthRate
-1 .68% Natural Gas + Allowance,
Y 10
RNG, Energy Efficiency,
C) 5 Allowances RTCs
Allowances (Free)
CD f� 00 M O T" N M � LO CD ti O M O T— N M � LO
N N N N M M M M M M M M M CO Iq qI qI qIq1* 41
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
2025 Natural Gas IRP Appendix 863
10 ,AJIVISTA

Public Meeting Written Feedback - Word Cloud
rP�
O � V
C '
of
m
(Owl
� -035s\c�`P���a�cP�� O ao
,a
e
�• tia \` aG
c ,o
e
e
�f°' ape �r1` •�°���
° a ff adrP �S�i, i�
°rdabili °y Cry
y ds
s�
2025 Natural Gas IRP Appendix 1� 864
,d,— VISTA

How Can You Get Involved
• Provide comments today or by email by March 14th
irp(@-avistacorp.com
• Join our Technical Advisory Committee (TAC)
https://www.mvavista.com/about-us/integrated-resource-planninq
• File comments with the IPUC (Idaho Customers)
- https://puc.idaho.gov/Form/CaseComment
• File comments with the OPUC (Oregon Customers)
- https://www.oregon.gov/puc/filing-center
• File comments with the WUTC (Washington Customers)
https://www.utc.wa.gov/e-filing
Email: [e-mail]
2025 Natural Gas IRP Appendix 865
12 40IIIIv 1sTA